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2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination | Draft 1

Description:

Start Date: 05/19/2022
End Date: 06/21/2022

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-011-3 IN 1 ST 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-011-3 05/19/2022 06/02/2022 06/08/2022 06/21/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-011-3 | Non-binding Poll IN 1 NB 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-011-3 | Non-binding Poll 05/19/2022 06/02/2022 06/08/2022 06/21/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 IN 1 ST 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 05/19/2022 06/02/2022 06/08/2022 06/21/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 | Non-binding Poll IN 1 NB 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination EOP-012-1 | Non-binding Poll 05/19/2022 06/02/2022 06/08/2022 06/21/2022
2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination Implementation Plan IN 1 OT 2021-07 Extreme Cold Weather Grid Operations, Preparedness, and Coordination Implementation Plan 05/19/2022 06/02/2022 06/08/2022 06/21/2022

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Hot Answers

No comment.

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

- 0 - 0

John Babik, JEA, 5, 6/21/2022

- 0 - 0

Other Answers

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

- 0 - 0

Manitoba Hydro believes that without the loads earmarked for UFLS and UVLS known, and considered in the planning stage, entities may not be able to provide sufficient load shed to weather sudden and long term system events.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

- 0 - 0

 If the new overlap language in the requirements will be retained, then TOPs will need access to this information. However, manual load shed at the transmission level will invariably impact distribution UFLS or UVLS as well as loads deemed critical by some entity. Reliability may be better served by requiring the Distribution Provider to know which distribution loads are critical or involve feeders involved in UFLS or UVLS, and require the Distribution Provider to manually shed load in response to an Operating Instruction from a Transmission Operator or Balancing Authority. When the Transmission Operator has to perform load shed at the transmission level, time is of the essence since there is no time to issue an Operating Instruction and load should be shed in the most efficient manner, which may mean taking some critical load and/or some load also involved in UFLS or UVLS.    

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

- 0 - 0

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

Avista presently avoids critical loads with its UFLS plan. The Manual Load Shedding is may contain some critical loads. There is extremely wide overlap between the UFLS and Manual Load Shedding. Given the nature of Avista’s system, the amount of load available for Manual Load Shedding will be greatly reduced under this standard. I recommend a NO vote with the following comment. “UFLS schemes are designed to address a multiple contingeny resource loss in real-time. They are not designed to be used during an Energy Emergency where there is no sudden frequency change. The UFLS loads are carefully chosen to avoid critical and sensitive loads. In many cases, the UFLS loads are also used for a manual load shed event, which by definition is slower, and not a frequency sensitive event. Manual Load Shedding is not occurring during a sudden frequency excursion. By limiting the overlap of the two load shedding schemes, flexibility of the BA/TOP to manage load resource balance in an EEA is severely compromised, and the amount of Manual Load Shedding available is greatly reduced. This will likely result in the interruption of critical loads during an EEA as the situation deteriorates and the System Operator is left with very limited options during an EEA.”

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

- 0 - 0

To ensure that all TOPs have the necessary data to minimize the overlap of circuits as required in the newly proposed EOP-011-3 R1.2.5.3, a review of PRC-006-5 R7 should be performed to minimize the redundancy between the PRC-006-5 and ECOP-011-4 standards. 

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

- 0 - 0

We do not have UVLS and we believe that PRC-006 and PRC-012 should NOT be modified.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

- 0 - 0

Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

- 0 - 0

In many cases, UFLS and UVLS are implemented on the distribution system, and thus the TOP may not have available detailed information to reflect these in their manual load shedding operations. 

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

In addition to revising PRC-006 and PRC-010, VELCO requests that the Standard Drafting Team revise EOP-011 with due consideration to areas of the ERO Enterprise for which the Transmission Operator does not serve as a Distribution Provider nor UFLS-Only Distribution Provider. For example, in Vermont, VELCO is a transmission-only TOP registered entity. VELCO serves DP and UFLS-Only DP registered entities, which have operational responsibility for both the sub-transmission and distribution system.

 

As defined in the Joint Inquiry Report (and is the practice in Vermont), “Load Shed” is “the reduction of electrical system load or demand by interrupting the load flow to major customers and/or distribution circuits, normally in response to system or area capacity shortages or voltage control considerations” (emphasis added).

 

Thus, in the event of an Emergency, VELCO would rely upon DP and UFLS-Only DP entities to (1) implement manual Load shedding in a timeframe adequate for mitigating the Emergency, (2) minimize the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads, (3) minimize the overlap of circuits that are designated for manual Load shed and circuits that are utilized for underfrequency load shed (UFLS) or undervoltage load shed (UVLS), and (4) limit the utilization of UFLS or UVLS circuits for manual Load shed to situations where warranted by system conditions.

 

As written, however, EOP-011 has the unintended consequence of requiring VELCO and other transmission-only entities to implement provisions that, in fact, Distribution Providers and UFLS-Only Distribution Providers are required to perform in order to mitigate operating Emergencies in Vermont’s Transmission Operator Area. A targeted approach to allow TOPs to identify, as necessary, DP and UFLS-Only DP entities that are required to mitigate operating Emergencies in a TOP’s Transmission Operator Area is therefore warranted. For the SDT’s reference, NERC Standard EOP-005-3 provides an illustrative example of a targeted approach for TOPs to both identify DPs and assign responsibilities to DPs based on need.

 

            Given the reasons stated, VELCO requests the following three (3) modifications to EOP-011:

 

1.      Add Distribution Provider and UFLS-Only Distribution Provider to the applicability section:

a.      4.1.4. Distribution Provider identified in the Transmission Operators Operating Plan to mitigate operating Emergencies”

b.      4.1.5. UFLS-Only Distribution Provider identified in the Transmission Operators Operating Plan to mitigate operating Emergencies”

 

2.      Add Requirement R1.2.5.5., stating:

a.      R1.2.5.5. Provisions for identifying Distribution Providers and UFLS-Only Distribution Providers required to mitigate operating Emergencies in its Transmission Operator Area.”

 

3.      Add a new Requirement R6, stating:

 

R6. Each Distribution Provider and UFLS-Only Distribution Provider identified in the Transmission Operators Operating Plan(s) as required to mitigate operating Emergencies in its Transmission Operator Area shall implement the following, as applicable: [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

6.1.            Operator-controlled manual load shedding during an Emergency that accounts for each of the following:

6.1.1. Provisions for manual Load shedding capable of being implemented in a timeframe adequate for mitigating the Emergency;

6.1.2.      Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads;

6.1.3.      Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that are utilized for underfrequency load shed (UFLS) or undervoltage load shed (UVLS); and

6.1.4.      Provisions for limiting the utilization of UFLS or UVLS circuits for manual Load shed to situations where warranted by system conditions.

Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

- 0 - 0

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

- 0 - 0

This will require periodic updates to ensure that UFLS and UVLS circuit data is accurate.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

- 0 - 0

The IESO is assuming the following:
1. TOP is responsible for establishing and implementating the Operating Plan.
2. TOP orders the maual load shed if and when required.
3. UFLS and UVLS load shedding entities make the arming selections (make the circuits available) for shedding.

The IESO strongly believes that the most effective means to ensure minimization of the overlap of circuits as required by the newly proposed EOP-011-3 is to add the UFLS and UVLS Load Shedding Entities as applicable functional entities.  Since UFLS and UVLS load shedding entities are responsible for the arming selections, they are the ones that implement the corrective load shedding circuit requirements.    

As such, the IESO requests that UFLS and UVLS load shedding entities be added as applicable functional entities in the newly revised EOP-011-3.

In addition, a new requirement should be added to the newly revised EOP-011-3 that requires the UFLS and UVLS Load Shedding Entities to meet the provisions included in the TOP Operating Plan for operator-controlled manual Load shedding during an Emergency that include:
1. Manual Load shedding capable of being implemented in a timeframe adequate for mitigating the Emergency
2. Minimizing the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads
3. Minimizing the overlap of circuits that are designated for manual Load shed and circuits that are utilized for UFLS or UVLS
4. Limiting the utilization of UFLS or UVLS circuits for manual Load shed to situations where warranted by system conditions.

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

- 0 - 0

IF EOP-011-3 is approved as is, BPA supports revising PRC-006 and PRC-010, and is not opposed to sharing its database data with adjacent TOPs, upon request.

Currently, and as written, BPA does not support the EOP-011-3 revisions. Please see BPA’s comments to this posting and, its reiterated SAR comments below. 

From BPA’s perspective, BPA directs entities to perform Manual Load Shed but it does not prescribe where and how to complete the task. BPA has no voice in how entites determine critical loads. BPA does not have distribution level diagrams for customer load within load centers (Citites, counties, etc.). It’s difficult to avoid overlap between Manual Load Shed and those that are armed for UFLS/UVLS.  Some overlap is inherent. PRC-006 NWPP Plans require a minimum 34.5% of BPA’s load to be armed for BPA’s UFLS. To allow for margin, and to maintain compliance, BPA actually has 38-40% armed for UFLS. BPA’s Manual Load Shed plan is for 38% of BPA’s load. This leads to the amount of breakers that can be opened. There’s only so many breakers that meet the requirements to be used in load shed.

 

BPA’s comments submitted to the SAR (Dec. 2021)

BPA’s UFLS plans avoid Natural Gas and other critical loads. If BPA issues a Manual Load Shed directive, it is up to the recipient of that directive to make an informed decision regarding which loads to shed within their distribution area. BPA prescribes a certain amount of MW load, within a certain amount of time, in the Manual Load Shed plan. Then, the recipient of the directive (Public Utility, etc.) decides which loads to shed. In order for BPA to meet the minimum requirements, for both Manual and Automatic Load Shed, it would equate to roughly ¾ of the load in BPA’s Balancing Authority Area. BPA believes it is not practical or feasible to completely minimize overlap between the Manual and Automatic Load Shed plans. BPA disagrees with the report’s recommendation pertaining to this issue, thus, does not recommend modifying any current Reliability Standards (PRC-006, PRC-010, etc.) at this time.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

Having multiple Requirements with the same intent will introduce risk of double (non-compliance) jeopardy.  PRC-010-2 R8 already states that the UVLS database be made available to TPs.  Likewise, PCR-006-5 R14 states that the PC shall respond to written comments from applicable entities that want this data.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 2 - 0

This will require periodic updates to ensure that UFLS and UVLS circuit data is accurate.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

- 0 - 0

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

- 0 - 0

Dominion Energy supports the EEI comments and agrees that for Transmission Operators to ensure they are meeting the intent of EOP-011, Requirement R1 subparts 1.2.5.2, 1.2.5.3 and 1.2.5.4, they will need the same database lists that are provided by the UFLS and UVLS entities to the responsible Planning Coordinator.  To ensure this is done and the required information is shared, PRC-006-5 Requirement R7 and PRC-010-2 Requirement R8 should be modified to include sharing with the affected Transmission Operator.  Additionally, this information/database should be circulated/shared whenever the PC receives an updated version, not just upon request by the TOP.   

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

All TOPs may not have the information needed to ‘minimize the overlap of circuits’.  Planning Coordinators gather the UFLS and UVLS data as part of their program design, so this modification to the Standards would ensure TOPs would be provided this information upon request

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

- 0 - 0

DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

ISO-NE does not support an additional requirement on the Planning Coordinator (PC) to provide data to the Transmission Operator (TOP).  The TOP is responsible for providing the PC with the relevant UFLS/UVLS circuit information as currently written. This would only serve to place an additional administrative burden on the PC.  The SDT should consider adding the UFLS/UVLS Distribution Providers to the Applicable Facilities for these requirements.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

- 0 - 0

Reclamation observes that coordination and planning information exchange is already covered in other standards. The addition of new requirements to these standards is unnecessary and would likely cause confusion.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

- 0 - 0

YES, by not requiring the option of the data to be shared, there is a good chance, a feeder could be used in both plans. 

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

- 0 - 0

WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

- 0 - 0

we support the RSC comments.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

- 0 - 0

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

Pacific Gas & Electric (PG&E) supports the comments provided by the North American Generators Forum (NAGF).

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

Texas RE agrees there should be a Requirement that Planning Coordinators shall provide UFLS and/or UVLS (as applicable) program database data to Transmission Operator’s upon request, in order to ensure that all TOPs have the necessary data to minimize the overlap of circuits as required in the newly proposed EOP-011-3 Requirement R1.2.5.3.  The System Operators will be more prepared with more information.

 

Texas RE recommends capitalizing “load” in 1.2.5 as it is a defined term in the NERC Glossary.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

- 0 - 0

NCPA, Segment(s) 4, 5, 6, 4/3/2020

- 0 - 0

AEPCO signed on to ACES comments below:

We support a  review of PRC-006-5 R7 and PRC-010-2 R8 standards during the next logical review cycle of those Standards but do not believe the suggested modifications is a high priority. We understand the importance of providing clarity on managing the data collection requirements associated with UFLS and UVLS programs.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

- 0 - 0

AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

No. Revisions to PRC-006 and PRC-010 are not necessary. The proposed revisions to EOP-011 are sufficient to address the related recommendation from The Report and obligate the Transmission Operator to have provisions in their Operating Plan to address these requirements. The Transmission Operator must determine how these provisions are handled for entities and load they may represent. 

Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

- 0 - 0

Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

- 0 - 0

NCPA agrees with the comments of IESO.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

- 0 - 0

Southern Company supports the EEI comments and would add language to the end of PRC-006-5 R7 and PRC-010-2 R8 stating, “… and to the affected Transmission Operators within 90 days of receiving an updated version of the database.”

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Tenaska is a generator owner and has no comment on this standard.

Mark Young, Tenaska, Inc., 5, 6/16/2022

- 0 - 0

UFLS schemes are designed to address a multiple contingeny resource loss in real-time. They are not designed to be used during an Energy Emergency where there is no sudden frequency change. The UFLS loads are carefully chosen to avoid critical and sensitive loads. In many cases, the UFLS loads are also used for a manual load shed event, which by definition is slower, and not a frequency sensitive event. Manual Load Shedding is not occurring during a sudden frequency excursion. By limiting the overlap of the two load shedding schemes, flexibility of the BA/TOP to manage load resource balance in an EEA is severely compromised, and the amount of Manual Load Shedding available is greatly reduced. This will likely result in the interruption of critical loads during an EEA as the situation deteriorates and the System Operator is left with very limited options during an EEA.

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

- 0 - 0

NCPA agrees with the comments of IESO.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

- 0 - 0

AEP does not see a reliability benefit in requiring that program database data be provided to the Transmission Operator’s upon request, and does not recommend revising PRC-006-5 Requirement R7 and PRC-010-2 Requirement R8.

Thomas Foltz, AEP, 5, 6/17/2022

- 0 - 0

Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

- 0 - 0

No. Revisions to PRC-006 and PRC-010 are not necessary.  The proposed revisions to EOP-011 are sufficient to address the related concerns. 

Glenn Pressler, CPS Energy, 3, 6/17/2022

- 0 - 0

N/A – Invenergy is not a Transmission Operator and has no comment on these proposed modifications.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

- 0 - 0

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

- 0 - 0

No. Revisions to PRC-006 and PRC-010 are not necessary.  The proposed revisions to EOP-011 are sufficient to address the related concerns. 

Robert Stevens, CPS Energy, 5, 6/17/2022

- 0 - 0

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

AE does not feel strongly that there is a need to modify PRC-006-5 R7 or PRC-010-2 R8.  As a TOP, AE is able to comply with the requirements without receiving the UFLS/UVLS program database data from the Planning Coordinator.

Michael Dillard, Austin Energy, 5, 6/17/2022

- 0 - 0

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

- 0 - 0

The Planning Coordinator’s program typically only identifies percentages of load for a given frequency and time “step”.  The actual specific feeders that are part of a UFLS program of UVLS program are determined by the “UFLS Entities” under the PRC-006 standard / the “UVLS Entites” under PRC-010. The TOP needs to know the specific feeders, and so the UFLS /UVLS entities would be the ones that need to provide that data to the TOP. This information is already shared between UFLS/UVLS Entities as their operations staff today, but not in a formal requirement.

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

- 0 - 0

Summer Esquerre, NextEra Energy, 5, 6/17/2022

- 0 - 0

I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

- 0 - 0

LPPC, Segment(s) 3, 1, 6/17/2022

- 0 - 0

AZPS supports EEI’s comments.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

- 0 - 0

N/A

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Having multiple Requirements with the same intent introduces confusion and the risk of double jeopardy for non-compliance. Coordination and planning information exchange is already covered in other standards. The addition or change of requirements is unnecessary.

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

- 0 - 0

For Transmission Operators to ensure they are meeting the intent of EOP-011, Requirement R1 subparts 1.2.5.2, 1.2.5.3 and 1.2.5.4, they will need the same database lists that are provided by the UFLS and UVLS entities to the responsible Planning Coordinator.  To ensure this is done and the required information is shared, PRC-006-5 Requirement R7 and PRC-010-2 Requirement R8 should be modified to include sharing with the affected Transmission Operator.  Additionally, this information/database should be circulated/shared whenever the PC receives an updated version, not just upon request by the TOP.   

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

WECC supports this project and all comments provided by WECC are for drafting team consideration in an attempt to provide clarity or improvement. It may not be necessary to modify PRC-006-5, R7, or PRC-010-2, R8, because TOPs should be able to obtain the required data from entities within their footprint via their Data Specification process required in TOP-003. However, if the drafting team believes it may be beneficial for reliability to specifically require this information from the PC, rather than leaving it up to the TOP to include it in their Data Specification process, WECC is not opposed to adding this requirement to the two Reliability Standards. 

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

- 0 - 0

No comment

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

- 0 - 0

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

- 0 - 0

Does not apply to us as GO/GOP.  Selected because N/A was not an option.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

- 0 - 0

This will minimize the overlap of circuits. This is a current business practice within our entity to avoid any overlap with the manual load shedding plan.

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

- 0 - 0

None.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

- 0 - 0

Michael Jones, National Grid USA, 1, 6/17/2022

- 0 - 0

Xcel Energy supports the comments of the Edison Electric Institute.

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

- 0 - 0

Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

- 0 - 0

Joe McClung, JEA, 1, 6/17/2022

- 0 - 0

PNM supports aligning revised EOP-011-3 with existing PRC-006-5 R7 and PRC-010-2 R8.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

- 0 - 0

Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

- 0 - 0

Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.  

Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

- 0 - 0

Capital Power believes that improvements in industry communication should be facilitated consistently across all regions through a centralized portal (i.e. Align) rather than through the addition of administrative compliance requirements.

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

- 0 - 0

No comment

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

- 0 - 0

In addition to revising PRC-006 and PRC-010, RSC requests that the Standard Drafting Team revise EOP-011 with due consideration to areas of the ERO Enterprise for which the Transmission Operator does not serve as a Distribution Provider nor UFLS-Only Distribution Provider. For example, in NPCC, there are transmission-only TOP registered entities. These TOPs serve DP and UFLS-Only DP registered entities, which have operational responsibility for both the sub-transmission and distribution system.

 

As defined in the Joint Inquiry Report (and is the practice in some parts of NPCC), “Load Shed” is “the reduction of electrical system load or demand by interrupting the load flow to major customers and/or distribution circuits, normally in response to system or area capacity shortages or voltage control considerations” (emphasis added).

 

Thus, in the event of an Emergency, transmission-only TOPs would rely upon DP and UFLS-Only DP entities to (1) implement manual Load shedding in a timeframe adequate for mitigating the Emergency, (2) minimize the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads, (3) minimize the overlap of circuits that are designated for manual Load shed and circuits that are utilized for underfrequency load shed (UFLS) or undervoltage load shed (UVLS), and (4) limit the utilization of UFLS or UVLS circuits for manual Load shed to situations were warranted by system conditions.

 

As written, however, EOP-011 has the unintended consequence of requiring transmission-only TOPs to implement provisions that, in fact, Distribution Providers and UFLS-Only Distribution Providers are required to perform in order to mitigate operating Emergencies. A targeted approach to allow TOPs to identify, as necessary, DP and UFLS-Only DP entities that are required to mitigate operating Emergencies in a TOP’s Transmission Operator Area is therefore warranted. For the SDT’s reference, NERC Standard EOP-005-3 provides an illustrative example of a targeted approach for TOPs to both identify DPs and assign responsibilities to DPs based on need.

 

            Given the reasons stated, RSC requests the following three (3) modifications to EOP-011:

 

{C}1.     Add Distribution Provider and UFLS-Only Distribution Provider to the applicability section:

{C}a.     4.1.4. Distribution Provider identified in the Transmission Operators Operating Plan to mitigate operating Emergencies”

{C}b.     4.1.5. UFLS-Only Distribution Provider identified in the Transmission Operators Operating Plan to mitigate operating Emergencies”

 

{C}2.     Add Requirement R1.2.5.5., stating:

{C}a.     R1.2.5.5. Provisions for identifying Distribution Providers and UFLS-Only Distribution Providers required to mitigate operating Emergencies in its Transmission Operator Area.”

 

{C}3.     Add a new Requirement R6, stating:

 

R6. Each Distribution Provider and UFLS-Only Distribution Provider identified in the Transmission Operators Operating Plan(s) as required to mitigate operating Emergencies in its Transmission Operator Area shall implement the following, as applicable: [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

{C}6.1.          Operator-controlled manual load shedding during an Emergency that accounts for each of the following:

6.1.1. Provisions for manual Load shedding capable of being implemented in a timeframe adequate for mitigating the Emergency;

{C}6.1.2.     Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads;

{C}6.1.3.     {C}Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that are utilized for underfrequency load shed (UFLS) or undervoltage load shed (UVLS); and

Provisions for limiting the utilization of UFLS or UVLS circuits for manual Load shed to situations were warranted by system conditions.

 

Additional information is required for a better assessment:

add clarification regarding overlap – physical versus frequency domain action overlap

Additional clarification is required regarding when manual load shedding is permitted for the load connected to a feeder part of the UFLS program (extra load margin required with respect to the minimum amount of load accounted for in the UFLS program)

Manual load shedding shall only be allowed to disconnect the critical load for a period of time that is less than the critical load outage withstand time, without having a negative impact.

Similar to the UFLS program it is the time to have a dynamic approach to the critical loads; they should be treated differently based on the assigned priority and the specifics of the load shedding event in terms of extent, duration, and weather condition/season.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

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NAGF Comments: Industry communication should be improved. To the extent that a registered entity needs information from another entity or part of their own entity, that information should be provided. This type of communication should not need a requirement to address communications between the two entities.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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TCPA is an organization with generators as members so we have no input on this question.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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OPC supports ACES comments:  We support a review of PRC-006-5 R7 and PRC-010-2 R8 standards during the next logical review cycle of those Standards but do not believe the suggested modifications is a high priority. We understand the importance of providing clarity on managing the data collection requirements associated with UFLS and UVLS programs.

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

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Additionally, we request that Distribution Provider (DP) and UFLS-Only Distribution Provider be added to the applicability section of EOP-011-3 as well as making the follotwng addtions to the Requirements:

Add Requirement R1.2.5.5. as follows:
R1.2.5.5. Provisions for identifying Distribution Providers and UFLS-Only Distribution Providers required to mitigate operating Emergencies in its Transmission Operator Area.”

Add a new Requirement R6, as follows:
R6. Each Distribution Provider and UFLS-Only Distribution Provider identified in the Transmission Operators Operating Plan(s) as required to mitigate operating Emergencies in its Transmission Operator Area shall implement the following, as applicable:  


6.1. Operator-controlled manual load shedding during an Emergency that accounts for each of the following:
6.1.1. Provisions for manual Load shedding capable of being implemented in a timeframe adequate for mitigating the Emergency;
6.1.2. Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads;
6.1.3. Provisions to minimize the overlap of circuits that are designated for manual Load shed and circuits that are utilized for underfrequency load shed (UFLS) or undervoltage load shed (UVLS); and Provisions for limiting the utilization of UFLS or UVLS circuits for manual Load shed to situations where warranted by system conditions.

 

Quintin Lee, Eversource Energy, 1, 6/20/2022

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PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

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Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #1.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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MidAmerican supports MRO NSRF’s comments. Having multiple Requirements with the same intent will introduce risk of double (non-compliance) jeopardy.  PRC-010-2 R8 already states that the UVLS data base be made available to TPs.  Likewise, PCR-006-5 R14 states that the PC shall respond to written comments from applicable entities that want this data.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

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Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

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We support a  review of PRC-006-5 R7 and PRC-010-2 R8 standards during the next logical review cycle of those Standards but do not believe the suggested modifications is a high priority. We understand the importance of providing clarity on managing the data collection requirements associated with UFLS and UVLS programs.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

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Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

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PPL NERC Registered Affiliates support EEI comments on Question 1. 

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

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The TOP will need the data from UFLS and UVLS applications to determine if overlap exists with manual load shed expectations. This data will also identify if any additional MWs can be shed manually at these locations once the automatic process has been completed.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

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FirstEnergy agrees with EEI’s comments.  

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

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PRC-006-5 mandates UFLS entities to “provide automatic tripping of Load in accordance with the UFLS program design” as provided by the Planning Coordinator (PC). Therefore, the PC does not necessarily identify specific circuits for load shed action. Further, PRC-010-2 follows the same pattern of PRC-006-5. Typically, the PC communicates to the UFLS/UVLS entities the amount of load shed needed. It is then up to the UFLS/UVLS entity, the Transmission Owner (TO) and/or Distribution Provider (DP), to identify specific circuits for installation of necessary equipment. Of these two functional registrations, it is the DP who has intimate knowledge of the existence of critical loads, such as flood control pumping stations, police and fire dispatch offices, hospitals, etc. The TOP typically does not have the ability to perform manual load shed action which can avoid critical loads. This must be done in the distribution level or in coordination with the DP who is able to identify which transmission circuits can be tripped that will avoid critical load loss. It is better to require the TOP to coordinate a manual load shed plan with the TO and DP within the EOP standards. The TO and DP have the UFLS/UVLS program implementation and critical load data needed to develop a manual load shed plan which would respect the automatic load shed blocks; the PC is not originator of any of the required data. PRC-006 and PRC-010 should not be mixed in with manual load shed planning. Further, developing UFLS and UVLS designated areas where critical loads are not impacted is challenging. Therefore, endeavoring to identify other loads for manual load shed not overlapping UFLS and UVLS may prove to be a compliance burden more devoted to documenting why overlapping is unavoidable.

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

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PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

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Constellation has no comments

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

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Constellation has no comments

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

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No comment, as Calpine Corporationis  a Generation Owner and/or Operator.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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CenterPoint Energy Houston Electric, LLS believes that PRC-006-5 Requirement R7 and PRC-010-2 Requirement R8 should not be modified to include a Requirement that Planning Coordinators shall provide UFLS and/or UVLS (as applicable) program database data to Transmission Operator’s. As in current practice, UFLS and/or UVLS program database data is coordinated at the Distribution/Transmission level for each applicable entity where loads and assessment of overlap of loads that serve critical loads are identified. This data is then provided to the Planning Coordinator to be implemented as part of the Planning Coordinator’s UFLS Program design. The proposed revisions to EOP-011-3 address the recommendations reported and require TOPs to incorporate the new criteria in their deployment and coordination of loads between manual load shed and UFLS/UVLS events.

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Natalie Johnson, Enel Green Power, 5, 6/21/2022

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The SRC does not support the addition of a new administrative requirement on the Planning Coordinator to provide UFLS/UVLS circuit information back to the Transmission Operator but rather mirror the applicability sections of the PRC Standards within the applicability section of EOP-011-3 and requests that EOP-011-3 be modified to ensure the applicable functional entities are identified and responsible for the Load shedding requirements of manual/automatic and UFLS/UVLS circuits.  This addition aligns with other NERC Standards where a subset of Distribution Providers and Transmission Owners are responsible for the ownership, operation, or control of the Load shedding circuits (one example is in the applicability section of PRC-010-2 where the functional entities are defined in detail to meet the applicable requirements.)

Proposed language for EOP-011-3

Applicability:   

Transmission Owners

Distribution Providers

UFLS-Only Distribution Providers

UVLS-Only Distribution Providers

R2.      Each applicable Transmission Owner and Distribution Provider responsible for the ownership, operation, or control of manual Load shedding; and UFLS-Only Distribution Providers and UVLS-Only Distribution Providers shall meet the provisions included in the Transmission Operating Plan for operator-controlled manual Load shedding during an Emergency that include:

R2.1    Manual Load shedding capable of being implemented in a timeframe adequate for mitigating the Emergency;

R2.2    Minimizing the overlap of circuits that are designated for manual Load shed and circuits that serve designated critical loads;

R2.3    Minimizing the overlap of circuits that are designated for manual Load shed and circuits that are utilized for UFLS or UVLS

R2.4    Limiting the utilization of UFLS or UVLS circuits for manual Load shed to situations where warranted by system conditions.

M2.     Each Transmission Owner and Distribution Provider responsible for the ownership, operation, or control of manual Load shedding; and UFLS-Only Distribution Providers and UVLS-Only Distribution Providers shall provide evidence of meeting its Transmission Operator’s Operating Plan(s) regarding provisions for operator-controlled manual Load shedding during an Emergency.

Per the Extreme Cold Weather Grid Operations, Preparedness, and Coordination SAR Phase 1, the need to include Transmission Owners (TOs) and Distribution Providers (DPs) is listed within the SAR: “4. In minimizing the overlap of manual and automatic load shed, the load shed procedures of Transmission Operators, Transmission Owners (TOs) and Distribution Providers (DPs) should separate the circuits that will be used for manual load shed from circuits used for underfrequency load shed (UFLS)/undervoltage load shed (UVLS) or serving critical load. UFLS/UVLS circuits should only be used for manual load shed as a last resort and should start with the final stage (lowest frequency). (Report Key Recommendation 1j)”   Manual and automatic load shed entities include applicable TOPS, TOs, and DPs and the addition to the Applicability section of EOP-011-3 is needed to support the expanded TOP Load shed provisions.

In the Joint Inquiry Report, under Section 2d. Preparedness for Emergency Operations; i. Manual and Automatic Load Shed Plans; reports “Distribution Providers (DP) have the responsibility for determining exactly which circuits are to be disconnected during a load shed event.”  The proposed revisions in EOP-011-3 will require the recognition of designated critical loads and minimizing any overlap of the circuits designated for manual Load shed.  This section of the Report also highlights DPs as being required to determine underfrequency relay locations in order to minimize the geographical area of underfrequency events.  Having the TO/DP added for UFLS (and UVLS) will ensure the correct circuits are used in minimizing the overlap between manual Load shed and UFLS/UVLS circuits.

Recommendation 10 includes Transmission Owners and Distribution Providers in coordinating Load shed plans.  This further justifies the need to include TOs and DPs in EOP-011-3 to require this coordination in both planning and real-time operations.  

 

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

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Q1. ERCOT supports the SRC comments and the addition of the proposed language to expand applicability and to establish a new requirement for applicable TOs, DPs, and DPs with UVLS and UFLS circuits.  As the SRC noted, the FERC/NERC Report on the February 2021 Cold Weather Outages under Section II.C.2.d, Manual and Automatic Load Shed Plans, states: “Transmission Service Providers and Distribution Providers (DP) have the responsibility for determining exactly which circuits are to be disconnected during a load shed event.”  Additionally, in Recommendation 10, the FERC/NERC Report highlights the importance of coordination between Transmission Owners with Distribution Providers in coordinating Load shed plans.  There is limited value added by placing the responsibility on the PC within this standard. If the provision of the database to others is determined to be necessary, the requirement should be included within the PRC standard.

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

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Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

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Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

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James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

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Hot Answers

Thank you for the opportunity to present our position regarding these proposed standards. A consistent theme that is presented in our responses is that many generators in the North, particularly Canada, successfully operate in extreme cold year after year. In addition, many generators operate in regions that do not have the type of reliability risk being addressed by this standard. Therefore, there should be no need for a definition of “winter season” for all regions of North America. However, if an entity is required to define it, TransAlta agrees with the comments provided by NRG Energy.  

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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We Support LPPC's Comments

John Babik, JEA, 5, 6/21/2022

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Other Answers

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

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Yes, but the SDT should consider that the utilities in a BA need to have the changeover between Summer to Winter limits coordintated, where a BA extends into differening climates, this presents a problem. For example, Lousiana Power’s summertime may begin earlier than Manitoba Hydro’s  summer limits conditions. This may be less of an issue when Dynamic limits come into effect in a few years.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

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 The Reliability Coordinator should make this determination for consistency across the RC footprint.    

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

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We don't think the BA should be held responsible for determining what is considered the “winter season”. EOP-012-1 section 4.2 lacks clarity and there are no requirements concerning this responsibility, nor is it mentioned in the TR!

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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This should be left up to the entity, there is no good one size fits all solution here. We believe that the GO or GOP could be responsible for this notification, in addition to notifications of projected cold weather events could be handled by the GO and GOP for some entities.

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

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As written, EOP-012-1 does not include BA as an applicable functional entity. SRP recommends that if the BA is required to perform a regulatory required function, like defining "winter season", then the BA should be listed as a responsible functional entity in the Applicability section, along with the GO and GOP.

Consider including a requirement in EOP-012-1 that specifies the BA's responsibility of working with the GO and GOP to define "winter season" and identify units that will or will not be available for that season. The BA needs input from the GOP and GO to understand the temperature and seasonal limitations for each unit to define the "winter season" and which units are summer peaking only.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

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The Standard does not currently require the BA to determine the winter season.  A new requirement should be added to ensure the BA provides the seasons to the GOs in its footprint.   

Suggested language for the Requirement: "The Balancing Authority shall determine the winter season for its footprint and shall inform each GO in its footprint of its determination, by [date] of each year for the ahead winter season commencing in that calendar year.” 

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

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BA’s can have a large geographical footprint making it inappropriate to establish a winter season criteria, which varies by site.  An additional complication is some generating stations have multiple BA’s. The GO or its TOP should be the one to determine the winter seasons. If the SDT elects to utilize the TOP, the TOP should establish a “winter season” on a Facility by Facility basis, much like they do with Voltage Schedules for VAR-001. If the SDT elects to have the GO establish its own “winter season” there should be a requirement regarding the establishment of that season, and the justification for when it occurs. 

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

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If there is a requirement for defining the winter season, NRG agrees the BA is the best entity that can define this for their respective region. However, it must be understood that within a large BA, there may be wide variability in temperature gradients across the BA’s footprint and that variability should be accounted for.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

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We find the criterion for freeze protection measures is clear (i.e., “capable of continuous operations at the documented minimum hourly temperature experienced at location since 1/1/1975…”) and it is just about determining the generating units it applies to, as long as the dates for the winter season are clear, and that it starts before the first freeze and ends after the last.

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

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If it is deceided that a requirement to declare a 'winter season' becomes applicable to BAs, BPA believes it's more clear for BAs base the 'winter season' on a date range (such as October-April).

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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The Balancing Authority (BA) is the best entity to determine what their “winter season” is.  The MRO NSRF recommends the SDT review NERC Reliability Standards to verify if a requirement(s) exists for the BA to actually determine a “winter season”.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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If there is a requirement for defining the winter season, NRG agrees the BA is the best entity that can define this for their respective region. However, it must be understood that within a large BA, there may be wide variability in temperature gradients across the BA’s footprint and that variability should be accounted for.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Dominion Energy supports the EEI comments that the BA is the entity to determine the “winter season.” However, in some BA regions the area may be very large, and the BA may need to define winter seasons differently in certain parts of their area.  To address this concern, we suggest language be added to require the BA to work with their respective GOs and GOPs to ensure the “winter season” is appropriately defined throughout their area of responsibility.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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BAs should also be obligated to inform GO/GOPs of their defined “winter season”.

 

The BA is the appropriate entity to determine the “winter season” for purposes of defining applicable generating units in proposed EOP-012-1.  Because applicability of EOP-012 hinges on the BA’s determination, the SDT should consider a Requirement, possibly in EOP-011, for the BA to make the determination and communicate it to the GOs in its footprint.  Proposed requirement language: “The Balancing Authority shall determine the winter season for its footprint, and shall inform each GO in its footprint of its determination, by [date] of each year for the winter season commencing in that calendar year.”

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

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DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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ISO-NE agrees with the SRC comment and suggested language:

The winter season is defined as a minimum of December through February unless the applicable Balancing Authority decide otherwise.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

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Reclamation observes that different definitions of the same term are likely to cause confusion, especially in areas where a single entity has facilities under the jurisdiction of multiple BAs. Reclamation recommends instead of defining “winter season” as a time period, the standard should direct entities to begin cold weather preparations when temperatures decrease toward 40 degrees and to implement preparations as temperatures decrease toward 30 degrees. Alternatively, Reclamation recommends a universal “winter season” be defined as October through April.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

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Recommend RC to be the entity to determine the “winter season” to minimize potential for different winter seasons defined by multiple BAs for a single registered entity.

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

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WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

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we support the RSC comments. Additionally,

How is the BA held responsible for determining what is considered the “winter season”? EOP-012-1 section 4.2 lacks clarity and there are no requirements concerning this responsibility, nor is it mentioned in the TR.

Local BA to provide the “winter season”. It is not the winter season that determines the applicability to Facilities (generating units), rather the potential for localized extreme weather condition.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

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As proposed, EOP-012-1 does not include the BA as an applicable functional entity. Tacoma Power recommends that if the BA is required to perform a regulatory required function, like defining “winter season”, then the BA should be listed as a responsible functional entity in the Applicability section, along with the GO and GOP.

Additionally, a Requirement should be included in EOP-012-1 that specifies the BA’s responsibility of working with the GO and GOP to define “winter season” and identify units that will or will not be available for that season. The BA needs input from the GOP and GO to understand the temperature and seasonal limitations for each unit to define the “winter season” and which units are summer peaking only.

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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PG&E  recommends that the individual GO's and GOP's determine their own respective "winter seasons".  The BA may not have the capability and resources to determine unique winter season dates across a large and diverse region. For example, in California, PG&E has cold weather in the Sierra foothills and at the same time, we have very moderate temperatures at our facilities located on the Pacific Ocean or the Central Valley for the "winter seasons".

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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Texas RE agrees the BA is the appropriate entity to determine the “winter season”.  Texas RE recommends the BA coordinate with its RC and the PA/PC so the RC and PA/PC understand when the winter season is determined.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

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NCPA, Segment(s) 4, 5, 6, 4/3/2020

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AEPCO signed on to ACES comments below:

We request that the SDT provide justification for selecting the BA as the entity rather than the RC. In addition, whichever entity is ultimately selected, we feel it would be beneficial to include this determination as it’s own requirement rather than leaving it in the Facilities definition section. In taking this approach, the entity would be identified as an “Applicable Entity” in section 4.1 Functional Entities of the standard.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

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AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

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NCPA agrees with the comments of Tri-State G and T Association, Inc.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

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Southern Company supports the EEI comments and supports the BA as the entity to determine the “winter season” so long as this determination is applied only to exempt summer peaking generators from the requirements of EOP-12-1 but does NOT determine the timing of when a generating plant should implement its Cold Weather Preparedness Plan each year.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Regardless of official entity that makes the determination, stakeholder input should be considered.

Mark Young, Tenaska, Inc., 5, 6/16/2022

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This should be left up to the entity, there is no good one size fits all solution here. We believe that the GO or GOP could be responsible for this notification, in addition to notifications of projected cold weather events that could be handled by the GO and GOP for some entities.

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

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NCPA agrees with the comments of Tri-State G and T Association, Inc.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

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AEP supports the BA being the entity to determine the “winter season” in their region.  However, in some BA regions the area may be very large, and the BA may need to define winter seasons differently in certain parts of their footprint.  To address this concern, we suggest language be added to require the BA to work with their respective GOs and GOPs to ensure the “winter season” is appropriately defined throughout their area of responsibility.

Thomas Foltz, AEP, 5, 6/17/2022

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Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

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The Standard as currently drafted does not require the BA to determine the winter season.  There should be a requirement the BA define and coordinate the seasons with the GOs in its footprint.  Add something like: “BA shall determine the winter season for its footprint and shall inform each GO in its footprint of its determination, by x-date of each year for the ahead winter season.”

Glenn Pressler, CPS Energy, 3, 6/17/2022

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Invenergy agrees that the BA is the appropriate entity to determine the winter season. Invenergy suggests that the BA be added as an applicable functional entity in EOP-012-1, and that a separate Requirement be added, which details the method(s) by which the BA will notify subject Generator Owners of their determination.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

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Invenergy agrees that the BA is the appropriate entity to determine the winter season. Invenergy suggests that the BA be added as an applicable functional entity in EOP-012-1, and that a separate Requirement be added, which details the method(s) by which the BA will notify subject Generator Owners of their determination. 

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

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The Standard as currently drafted does not require the BA to determine the winter season.  There should be a requirement the BA define and coordinate the seasons with the GOs in its footprint.  Add something like: “BA shall determine the winter season for its footprint and shall inform each GO in its footprint of its determination, by x-date of each year for the ahead winter season.”

Robert Stevens, CPS Energy, 5, 6/17/2022

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BA Requirement to determine and communicate definition of winter season
The BA is the appropriate entity to determine the “winter season” for purposes of defining applicable generating units in proposed EOP-012-1.  Because applicability of EOP-012 hinges on the BA’s determination, the SDT should consider a Requirement, possibly in EOP-011, for the BA to make the determination and communicate it to the GOs in its footprint.  Proposed requirement language: “The Balancing Authority shall determine the winter season for its footprint, and shall inform each GO in its footprint of its determination, by [date] of each year for the winter season commencing in that calendar year.”  

Communication of plan to operate
In addition, to avoid the potential for disagreements over what constitutes a “plan” to operate, EOP-012-1 Section 4.2 could be revised to include communication of the GO’s plan to its BA.

Proposed language is attached in redline and clean format.

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

TAPS proposed language Q2.docx

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AE recommends adding the BA as a functional entity under the applicability section and have the requirement of defining the winter season clearly stated as a responsibility of BA with input from GO & GOP.

Michael Dillard, Austin Energy, 5, 6/17/2022

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ACP supports the BA determining the winter season.  It makes sense to determine the winter season in a way that accounts for regional/geographic differences in weather.  And, having the BA determine the winter season rather than individual generator owners will provide uniformity in approach for a given area, which is helpful in ensuring generators are subject to the same requirements.

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

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FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

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Summer Esquerre, NextEra Energy, 5, 6/17/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

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As proposed, EOP-012-1 does not include the BA as an applicable functional entity. LPPC recommends that if the BA is required to perform a regulatory required function, like defining “winter season”, then the BA should be listed as a responsible Functional Entity in the Applicability section, along with the GO and GOP.

Additionally, a Requirement should be included in EOP-012-1 that specifies the BA’s responsibility of working with the GO and GOP to define “winter season” and identify units that will or will not be available for that season. The BA needs input from the GO and GOP to understand the temperature and seasonal limitations for each unit to define the “winter season” and which units are summer peaking only.

These comments have been endorsed by LPPC.

LPPC, Segment(s) 3, 1, 6/17/2022

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AZPS supports EEI’s comments.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

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Agree with NAGF comments

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

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Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

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EEI supports the BA as the entity to determine the “winter season”, however, EOP-012 does not specifically set a requirement for the BA to define the winter season.  In EOP-012, the Applicability Section is the only place where this is mentioned.  Additionally, in some BA regions the area may be very large, and the BA may need to define winter seasons differently across the area.  To address this concern,  language should be added to a requirement that obligates the BA to both define the “winter season” and to work with their respective GOs and GOPs to ensure the “winter season” is appropriately defined throughout their area of responsibility.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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WECC is not opposed to this but offers the following options. The terminology for winter season is widely used for Facility Ratings, System Operating Limits, and Planning purposes. To avoid possible confusion, some consideration might be given to allowing the PC or RC to make this determination. This could allow for consistent terminology between cold weather operations and planning activities. Another consideration is whether it is appropriate to allow a Generator Only BA to establish the winter season for the benefit of its own generation (see suggested language in response to question 3). Another alternative or additional language might include a requirement that the BA determine and identify the “winter season” criteria, make formal declarations of the seasonal status, and communicate those to the GO/GOP.

 

 

 

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Colorado Springs Utilities agrees with comments endorsed by LPPC

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

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 The SDT appropriately proposes for the applicable Balancing Authority (BA) to define "winter season." This approach recognizes the impact of geographical location on the timing of the winter season. For example, in the Texas Reliability Entity, Inc. (Texas RE) region, the BA (the Electric Reliability Council of Texas, Inc. (ERCOT)) defines "winter season" as December through February, rather than including any portion of March, which typically has milder temperatures in Texas.    

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

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Entergy agrees but would like clarity on consistency of the winter season from year to year and north vs south. 

Entergy, Segment(s) 1, 5, 12/13/2017

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Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

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Irrelevant who determines "winter season".  Practical outcome is that generating facilities need to prepare no matter who selects the "winter season."  Selected because N/A was not an option.  

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

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As proposed, EOP-012-1 does not include the BA as an applicable functional entity. IID recommends that if the BA is required to perform a regulatory required function, such as defining “winter season”, then the BA should be listed as a responsible functional entity in the Applicability section, along with the GO and GOP.

Additionally, a Requirement should be included in EOP-012-1 that specifies the BA’s responsibility of working with the GO and GOP to define “winter season” and identify units that will or will not be available for that season. The BA needs input from the GOP and GO to understand the temperature and seasonal limitations for each unit to define the “winter season” and which units are summer peaking only.

In addition, further guidance is needed on the exclusion of generators but which could be called upon by the BA (specifically since the BA is not listed as a functional entity).  

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

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Section 4.2 - Facilities states “The winter season will be determined by the generating unit’s applicable Balancing Authority.”  Duke Energy suggest this sentence be removed.  Additionally, per the NAGF, “there is not a requirement that addresses anything being done during the winter period.  All requirements address cold weather issues.  For this reason, it is recommended that this sentence be struck from the applicability.”

If the current language is not removed:

(a) Balancing Authorities (BA) as a Function Entity should be added to Section 4.1 – Functional Entities to ensure BA’s have a compliance obligation to provide “winter season” information to generating unit’s , and

(b) The SDT should add appropriate BA submittal language to a new or existing Requirement to ensure the action is enforceable and “winter season” information is submitted by the BA.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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I agree with TAPs comments, pasted below:

BA Requirement to determine and communicate definition of winter season

The BA is the appropriate entity to determine the “winter season” for purposes of defining applicable generating units in proposed EOP-012-1.  Because applicability of EOP-012 hinges on the BA’s determination, the SDT should consider a Requirement, possibly in EOP-011, for the BA to make the determination and communicate it to the GOs in its footprint.  Proposed requirement language: “The Balancing Authority shall determine the winter season for its footprint, and shall inform each GO in its footprint of its determination, by [date] of each year for the winter season commencing in that calendar year.” 

Communication of plan to operate

In addition, to avoid the potential for disagreements over what constitutes a “plan” to operate, EOP-012-1 Section 4.2 could be revised to include communication of the GO’s plan to its BA.

Proposed language (clean)

For purposes of this standard, the term “generating unit” means each Bulk Electric System generator that has informed its Balancing Authority that it plans to operate during the upcoming winter season that has been determined by the generating unit’s applicable Balancing Authority pursuant to EOP-011-3 Requirement R***.  The term excludes those generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies.

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

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Michael Jones, National Grid USA, 1, 6/17/2022

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We support the comments of EEI; it is appropriate that the BA  determines the "winter season"

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

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TMLP echoes the comments submitted by TAPS Group: 

BA Requirement to determine and communicate definition of winter season

 

The BA is the appropriate entity to determine the “winter season” for purposes of defining applicable generating units in proposed EOP-012-1.  Because applicability of EOP-012 hinges on the BA’s determination, the SDT should consider a Requirement, possibly in EOP-011, for the BA to make the determination and communicate it to the GOs in its footprint.  Proposed requirement language: “The Balancing Authority shall determine the winter season for its footprint, and shall inform each GO in its footprint of its determination, by [date] of each year for the winter season commencing in that calendar year.” 

 

Communication of plan to operate

In addition, to avoid the potential for disagreements over what constitutes a “plan” to operate, EOP-012-1 Section 4.2 could be revised to include communication of the GO’s plan to its BA.

Proposed language (clean)

For purposes of this standard, the term “generating unit” means each Bulk Electric System generator that has informed its Balancing Authority that it plans to operate during the upcoming winter season that has been determined by the generating unit’s applicable Balancing Authority pursuant to EOP-011-3 Requirement R***.  The term excludes those generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies.

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

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Determining the winter season should be applicable to GOs.  GO actions within the requirements should have deadlines set by the GO.  The BA could be located in a different weather zone than the GO’s Facilities and therefore not familiar enough with the details to choose a date range that matches local conditions.  The BA is not listed under Applicability/Functional Entity.

Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

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We support LPPC's comments.

Joe McClung, JEA, 1, 6/17/2022

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PNM supports comments submitted by EEI.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

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Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

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Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

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Captial Power believes that focus should be on operation capability during certain weather / temperatureconditions rather than arbitrarily chosen seasons. Capital Power supports the NAGF revisions which eliminate the need for the definition of this term.

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

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The BAs are best positioned to determine their winter season based on region-specific characteristics, their own analysis, and their own stakeholder input.

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

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How is the BA held responsible for determining what is considered the “winter season”? EOP-012-1 section 4.2 lacks clarity and there are no requirements concerning this responsibility, nor is it mentioned in the TR.

 

Local BA to provide the “winter season”

It is not the winter season that determines the applicability to Facilities (generating units), but rather the potential for localized extreme weather conditions.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

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NAGF Comments: The NAGF believes there is no need to define the winter season. The NAGF proposed revisions to EOP-012-1 eliminate the need for such a definition.  

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

NAGF EOP-012-1 06152022 final.pdf

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It should either be the BA or the agency with regulatory oversite of the Balancing Authority. Within a large BA, there may be wide variability in temperature gradients across the BA’s footprint and that variability should be accounted for. Regardless, stakeholder input should be allowed in determining the winter season.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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OPC supports ACES comments: We request that the SDT provide justification for selecting the BA as the entity rather than the RC. In addition, whichever entity is ultimately selected, BA of RC, we feel it would be beneficial to include either this determination as it’s own requirement rather than leaving it in the Facilities definition section. In taking this approach, the entity would be identified as an “Applicable Entity” in the standard. 

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

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Quintin Lee, Eversource Energy, 1, 6/20/2022

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CHPD agrees with LPPC's comments.

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

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Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #2.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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MidAmerican supports EEI comments. MidAmerican supports the BA as the entity to determine the “winter season”, however, EOP-012 does not specifically set a requirement for the BA to define the winter season.  In EOP-012, the Applicability Section is the only place where this is mentioned.  Additionally, in some BA regions the area may be very large, and the BA may need to define winter seasons differently across the area.  To address this concern, language should be added to a requirement that obligates the BA to both define the “winter season” and to work with their respective GOs and GOPs to ensure the “winter season” is appropriately defined throughout their area of responsibility.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

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Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

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We request that the SDT provide justification for selecting the BA as the entity rather than the RC. In addition, whichever entity is ultimately selected, we feel it would be beneficial to include this determination as it’s own requirement rather than leaving it in the Facilities definition section. In taking this approach, the entity would be identified as an “Applicable Entity” in section 4.1 Functional Entities of the standard. 

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

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Southern Indiana Gas & Electric Company (SIGE) supports EEI’s comment. SIGE supports the BA  as the entity to determine the “winter season”; however, EOP-012 does not specifically set a requirement for the BA to define the winter season.  The SDT should consider adding the BA requirement to either the Standard language or the Applicability section.

 Additionally, in some BA regions the area may be very large, and the BA may need to define winter seasons differently across the area.  To address this concern, language should be added to a requirement that obligates the BA to both define the “winter season” and to work with their respective GOs and GOPs to ensure the “winter season” is appropriately defined throughout their area of responsibility.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

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PPL NERC Registered Affiliates support EEI comments on Question 2. 

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

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Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

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FirstEnergy agrees with EEI’s comments.  

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

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The burden should be on the GO to identify the “winter season,” or better, the yearly time span of heightened cold weather risk to the affected Balancing Authority (BA) entities. Further, the GOP can communicate real time heightened risk to the affected BAs to allow for contingency planning. As far as defining applicable generating units in proposed EOP-012-1 Section 4.2 Facilities, it is better to first assume all BES generation is applicable, then define a list of exclusions. Certain generation units are highly unlikely to be directly impacted by cold weather and can demonstrate this via historical data extending back 60 years. Reliability efforts should not be incumbered with compliance and monitoring activity with little to no return in benefit to BES stability.

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

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PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

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Constellation Energy Generation (CEG) does not agree the BA should be the authority on determining cold weather, rather the GO/GOP is in the best position to make the determination of defining the winter season based on regional climate differences. Also, the BA is not included in the standard as an applicable entity and therefore should not have the ability to make this determination. Constellation suggests also that "winter season" should not be defined in the standard based on these regional variances.  The current title of the draft EOP-012 is "Extreme Cold Weather", not "Winter".  Removing the limitation of a defined "winter" season helps ensure generator availability for any cold weather period.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

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Constellation Energy Generation (CEG) does not agree the BA should be the authority on determining cold weather, rather the GO/GOP is in the best position to make the determination of defining the winter season based on regional climate differences. Also, the BA is not included in the standard as an applicable entity and therefore should not have the ability to make this determination. Constellation suggests also that "winter season" should not be defined in the standard based on these regional variances.  The current title of the draft EOP-012 is "Extreme Cold Weather", not "Winter".  Removing the limitation of a defined "winter" season helps ensure generator availability for any cold weather period.

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

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Yes, the BA (or the agency with regulatory oversite of the Balancing Authority) should be the entity to determine the “winter season.” This approach accounts for variability in temperature as relates to geographical location. For example, in the Texas RE region, the BA defines the “winter season” as December through February , excluding March, as March is usually a month that experiences milder temperatures in that region.  Additionally, the BA (or equivalent entity) is most well-suited to account for climate variability within the sub-regions of the BA itself. Additionally, Calpine proposes that stakeholder input should be allowed and considered in determining the “winter season.” 

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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The BA is in the best position to determine the “winter season”  as they have the first hand knowledge of their planning area and the visibility of entire system as a whole.  This also ensures consistency throughout the region.

Natalie Johnson, Enel Green Power, 5, 6/21/2022

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The SRC proposes the following language change: The winter season is defined as December through February unless the applicable Balancing Authority decides otherwise.

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

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Q2. ERCOT supports the SRC proposed language that proposes a default winter period, but agrees that BA discretion to identify a different definition of winter is appropriate. 

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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SNPD supports comments submitted by LPPC and Tacoma Power

Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

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Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

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If there is a requirement for defining the winter season, LCRA agrees the BA is the best entity that can define this for their respective region.

Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

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If there is a requirement for defining the winter season, LCRA agrees the BA is the best entity that can define this for their respective region.

James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

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Hot Answers

TransAlta agrees with exempting the facilities identified. Many generators in the North, particularly Canada, successfully operates in extreme cold year after year. In addition, many facilities operate in regions that do not have the type of reliability risk being addressed by this standard. For those entities, this standard is creating a significant administrative burden. Therefore, there should be further language that exempts those generators in regions where there is little or no reliability risk. 

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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We may be in agreement with the intention, but the language needs revision. All generators not planned to run during the winter should be excluded. Is this the intention? If so, the last sentence in 4.2 Facilities should read, “The term excludes those generators that are not included in the winter season plan.” As mentioned in LPPC comments, a separate Requirement should be included in EOP-012-1 which defines “winter season” AND identifies the units. If this were the case, no mention of emergency is needed

John Babik, JEA, 5, 6/21/2022

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Other Answers

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

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Capacity emergencies occur in a variety of seasons.  This exemption for peaking units will continue the trend of units not being weatherized and fall short of the overall goal, which is to prevent a repeat of the February, 2021 severe winter storm events in Texas.  Listing specific criteria for the exemptions in the standard is preferred.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

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 With the changing generation mix on the electric grid and projected capacity and energy shortfalls by various reliability entities, no BES unit should be exempt from EOP-012 since all may be called on in an extreme cold weather event when other units are unable to start or operate.    

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

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Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

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N/A- SEC does not operate under winter weather conditions as much of the United States does, therefore, SEC has no opinion.

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

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We believe that it is more appropriate to have the meaning of “generating unit” or the exclusion of those generators that do not operate during the winter season, except for as called upon by the BA, in the standard requirement rather than in the Applicability.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

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Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

VELCO requests that the SDT consider Emergencies in the summer weather season that may warrant protections.

Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

- 0 - 0

If there is any chance of the plant operating during any cold weather energy emergency then the standard should apply. Some of the primary issues in past cold weather events have been tied to units that were not expecting to operate at the time. Tri-State does not believe any exemption would be in the best interest of the BES.

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

- 0 - 0

NRG generally agrees with the concept on exemptions for summer run only units. Typically penalization of unit operation is related to market rules. Therefore penalties should not be considered under NERC jurisdiction. However, if this becomes a NERC requirement, this could unfairly subject an entity to double jeopardy.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

- 0 - 0

The IESO strongly believes that the standard should apply to all the generating units whose capacity is being counted on, including those providing sufficient reserve to withstand a cold weather event.

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

- 0 - 0

BPA supports the comments submitted by the US Bureau of Reclamation.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

The proposed changes are subjective and allow for the exclusion of the very units this project should be attempting to make more reliable and resilient, which is those called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies. The exclusion of these generators could be detrimental to the reliability and resilience of the BES. The inability of such generators to operate in extreme conditions could manifest as a false sense of security and ultimately contribute to the emergency rather than help alleviate it. Further, if the language were to remain as proposed, there is no explanation or definition on determining units as “plan to operate” or “do not operate” during the winter season. 

 

The MRO NSRF suggests that all BES generators should be included in proposed section 4.2 and therefore the language should remain unchanged from EOP-011-2, section 4.2 Facilities. BES generators such as summer peaking units or those that do not plan to operate in the winter season would have the opportunity to declare exemption through R1.4.4. 

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 2 - 0

NRG generally agrees with the concept on exemptions for summer run only units. Typically, penalization of unit operation is related to market rules. Therefore, penalties should not be considered under NERC jurisdiction. However, if this becomes a NERC requirement, this could unfairly subject an entity to double jeopardy.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

- 0 - 0

BC Hydro appreciates the opportunity to comment and has the following comment seeking additional clarification on the assessment of the freeze protection measures, specifically for generating facilities that are not directly exposed to extreme cold, i.e. located at least partially indoors. BC Hydro’s understanding is that the required assessment will be on facility-by-facility basis (or type of facilities), and will need to account for all equipment that would be exposed to extreme cold temperatures. Please confirm whether our understanding is accurate.

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

- 0 - 0

Dominion Energy supports the NAGF comments and agrees that since existing plants should not be required to retrofit and only provide their operational constraints a winter season is not necessary.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

- 0 - 0

DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

Note: BES generating units only; NERC rules do not extend to all Market Participants

 

Problematic phrasing?

4.2.        Facilities: For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that plan to operate during the winter season. The winter season will be determined by the generating unit’s applicable Balancing Authority. The definition excludes those generators that do not operate during the winter season except and are not otherwise required by the BA to be available during Capacity Emergencies or Energy Emergencies.  

ISO-NE agrees with the SRC Comments for the proposed Applicable Facilities language and reiterates the concern; Can units operate during one winter season and not the next or vice versa? If so, how will this be treated under the standard since the implementation period is longer than one year? The SRC views this as problematic as units could opt in and out of operating during the “winter season” to avoid the regulation, thereby negating the intended benefits of this standard.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

- 0 - 0

The information in the Facilities section is unclear. The phrase “BES generators that plan to operate during the winter season” is unclear and confusing. Equipment does not plan anything. Is the language referring to Generator Owners or Generator Operators that plan to operate generating units during the winter? It is unclear if the exclusion of “generators that do not operate during the winter season” refers to Generator Owners, Generator Operators, or generating units. It is unclear why generating units that would be called upon during certain Emergencies would be exempt from requirements that arose out of equipment failures to perform during emergency situations.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

- 0 - 0

This is already an industry standard/best practice.

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

- 0 - 0

WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

- 0 - 0

HQ experiences winter peaking months

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

- 0 - 0

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

PG&E supports the comments provided by the North American Generators Forum (NAGF).

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

Texas RE agrees with and supports proposed Reliability Standard EOP-012-1.  Texas RE is concerned, however, with section A. 4.2. The Facilities language does not indicate that it is exempting those units utilized for summer peaking purposes only as this question states.  Texas RE recommends clarifying that any generating unit that could be called upon by the BA be included in the applicability of EOP-012-1.  Those entities who are needed at during Capacity Emergencies and Energy Emergencies need to be appropriately prepared for extreme weather.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

- 0 - 0

NCPA, Segment(s) 4, 5, 6, 4/3/2020

- 0 - 0

AEPCO signed on to ACES comments below:

In regards to the proposed Section 4.2 Facilities definition:  In order to ensure a reliable response from generators that may be called upon by the Balancing Authorities during Capacity and Energy Emergencies, we recommend eliminating the exception for generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies. Our recommended change to the language would be “The term excludes those generators that are not expected to operate during the winter season under normal and/or emergency conditions.”

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

- 0 - 0

AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

- 0 - 0

Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

- 0 - 0

NCPA agrees with the comments of MRO NSRF.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

- 0 - 0

Southern Company supports the EEI comments.  In addition, Southern would like more clairity on the definition of “non-winter units” and what criteria would deem a unit to be exempt from the requirements of EOP-012-1. 

We also suggest defining what advance notice is required when detemiming and communicating which units are exempt from EOP-012. 

We suggest modifying the wording in 4.2 from “For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that plan to operate during the winter season.” to “For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that are expected to operate during the winter season by their applicable BA.”

 

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Mark Young, Tenaska, Inc., 5, 6/16/2022

- 0 - 0

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

- 0 - 0

NCPA agrees with the comments of MRO NSRF.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

- 0 - 0

AEP supports the exclusion of units designated for summer peaking-only from the requirements of EOP-012-1, and supports the comments of EEI in that regard.

AEP recommends that 4.2 (Facilities) be revised to state “… the term excludes those generators, *as defined by the Balancing Authority*, that do not operate…”

Thomas Foltz, AEP, 5, 6/17/2022

- 0 - 0

Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

- 0 - 0

No; capacity emergencies occur in all seasons, especially winter.  An exemption for generation unit(s) will continue the trend of units not being weatherized and fall short of the overall goal, which is to prevent a repeat of the February 2021 severe winter storm event.  Any specific criteria for any such exemption(s) should be included in the actual requirement wording.  We do have a concern that some generators will just say they do not operate during the winter and thus create further winter capacity issues.  

Glenn Pressler, CPS Energy, 3, 6/17/2022

- 0 - 0

Invenergy agrees with the applicability of EOP-012-1 as drafted.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

- 0 - 0

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

- 0 - 0

No; capacity emergencies occur in all seasons, especially winter.  An exemption for generation unit(s) will continue the trend of units not being weatherized and fall short of the overall goal, which is to prevent a repeat of the February 2021 severe winter storm event.  Any specific criteria for any such exemption(s) should be included in the actual requirement wording.  We do have a concern that some generators will just say they do not operate during the winter and thus create further winter capacity issues. 

Robert Stevens, CPS Energy, 5, 6/17/2022

- 0 - 0

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

N/A

Michael Dillard, Austin Energy, 5, 6/17/2022

- 0 - 0

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

- 0 - 0

While we agree with having the BA determine, there needs to be a requirement for coordination amongst adjacent BAs. They don’t have to have matching definitions but they need to understand the implications of having one BA with a dramatically different definition than its neighbor.

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

- 0 - 0

Summer Esquerre, NextEra Energy, 5, 6/17/2022

- 0 - 0

I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

- 0 - 0

LPPC, Segment(s) 3, 1, 6/17/2022

- 0 - 0

AZPS supports the SDT’s approach to exempt generating units that do not operate during the winter season. As noted by EEI, the term ‘peaking’ is not used in the Reliability Standard.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

- 0 - 0

Agree with NAGF comments

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

The language used, such as "do not operate" or "plan to operate" is unclear and confusing and could potentially exclude those very generating units that would be called upon during certain Emergency situations. 

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

- 0 - 0

EEI supports the SDT’s approach, which exempts units utilized for all periods except for the winter season, noting that the term “peaking” is not used in the Reliability Standard.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

WECC agrees with the concept, but the proposed wording appears to allow each individual GO to determine if it plans to operate during a winter period. Ambiguity could be reduced (and a more consistent use of the term “winter season” could be achieved) by modifying Applicability Section 4.2 to read: “For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that have been studied as “in operation” during winter seasonal studies and base cases performed by the PC or TP where the unit is located. Nothing in this standard is intended to prevent requesting the operation of any generating unit by a Balancing Authority during Capacity Emergencies or Energy Emergencies.” An alternative option may be to include language such as “entities that offer generation day-ahead during the winter season” or “entities whose generation is picked up in the day-ahead market.”

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

- 0 - 0

The SDT appropriately focuses the draft standard on winterization measures, as emergency grid conditions tend to occur more frequently in the winter than in the summer season. The draft standard also appropriately limits those winterization requirements to resources that operate in winter, as there is no need for a resource that does not operate in the winter to establish or maintain winterization measures.

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

- 0 - 0

At this current time, this is not applicable to Entergy.

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

No comments.

George Brown, Acciona Energy North America, 5, 6/17/2022

- 0 - 0

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

- 0 - 0

An exemption for units only operated in the summer months would be welcome.

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

- 0 - 0

A winter exemption creates potential BES reliability challenges from a resource planning, reserve margin, forecasted load, etc. perspective.  Duke Energy does not agree with the proposed winter weather season unit exemption unless meaningful, enforceable, defined, and vetted exemption criteria are developed and incorporated into the proposed Standard.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

- 0 - 0

Michael Jones, National Grid USA, 1, 6/17/2022

- 0 - 0

Xcel Energy supports the comments submitted by EEI and the NAGF.

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

- 0 - 0

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

- 0 - 0

The phrase “do not operate during the winter season except when called upon by the BA needs a standalone definition.  Most entities have units that are only called upon during extreme weather events.

Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

- 0 - 0

We may be in agreement with the intention, but the language needs revision. All generators not planned to run during the winter should be excluded. Is this the intention? If so, the last sentence in 4.2 Facilities should read, “The term excludes those generators that are not included in the winter season plan.” As mentioned in LPPC comments, a separate Requirement should be included in EOP-012-1 which defines “winter season” AND identifies the units. If this were the case, no mention of emergency is needed.

Joe McClung, JEA, 1, 6/17/2022

- 1 - 0

No additional comment.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

- 0 - 0

Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

- 0 - 0

Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments.  

Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

- 0 - 0

As drafted the applicability of the standard may create adverse impacts on competitive electricity markets  in that it may disincentify Market Participants from operation during winter months due to a higher burden of compliance. Capital Power encourages the SDT to ensure the applicability of the standard considers NERC’s Market Principles and all types of Market Partipants, including those that may not be unable to recover costs by passing them through to end users (ie. Independent Power Producers). In general, Capital Power supports the NAGF comments on this question.

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

- 0 - 0

In lieu of R1 of EOP-012-01 we recommend that R2 of EOP-011-03 be enhanced to require each BA to quantify the amount of reliable generation it needs to meet extreme cold weather conditions and place the requirement on the BA to identify the specific generators that are designated to provide the service under the BA’s specified ambient conditions.  This also has the benefit of ensuring that the amount of reliable generation and the degree to which the generation is reliable, including attributes besides freeze protection, is matched closely with the BA’s mitigating requirements of R2.  This proposal would achieve similar or better reliability benefits at less cost than the current proposal.  The BA would also be able to match the weatherization requirements with their regional fuel needs; it is unnecessary and inefficient to require generators that likely may not be able to operate for reasons other than freeze protection (e.g., fuel unavailability, environmental limitations, cooling water supply issues, etc.) to winterize to such an extreme requirement.  The BA may also be able to include financial incentives and penalties for absolute performance (i.e., no excuses) in its tariff design that cannot be replicated in a Reliability Standard; we foresee circumstances where generators may make made good faith efforts, comply with the Reliability Standards, but ultimately fail to perform during extreme cold weather events.

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

- 0 - 0

RSC requests that the SDT consider Emergencies in the summer weather season that may warrant protection.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

- 0 - 0

NAGF Comments: As drafted, the applicability section is likely to drive rational Generator Owners from the winter period due to the uncertainty of what may be required to meet the obligations in the EOP-012-1 requirements. Additionally, it appears that the Balancing Authority could call upon a generator to run during a period that is not considered a Capacity or Energy Emergency and thereby cause the generator to be subject to the standard. As worded, it is unclear if the Balancing Authority can only call upon the generators once an emergency has been declared by the Reliability Coordinator or if the Balancing Authority is anticipating an emergency. Each of these issues would need to be addressed to ensure the potential for unintended consequences is reduced.

The NAGF is providing a revised OP-012-1 standard for consideration that addresses these issues in a holistic manner.

Generators should not be placed in a position that by running they become subject to a standard unless they have contracted/agreed with an entity, to provide that service, similar to EOP-005. Under EOP-005, all generators capable of providing blackstart service are not required to comply; compliance is mandatory only for those generators that have contracted for blackstart service. EOP-012 should only apply to those generators that have agreed to be available to provide service under all conditions, not just by operating during specific months or time periods during the year. 

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

NAGF EOP-012-1 06152022 final.pdf

- 0 - 0

EOP-012-1 should only be applied to units that participate in the market during the winter season. Note that the potential cost implications of R1 which can be millions if not tens of millions of dollars, which may result in generators either retiring or opting out of the winter season. Unfunded mandates such as R1 that have such a high material economic impact may ultimately reduce winter season reliability due to reduced generation available for dispatch.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

- 0 - 0

Quintin Lee, Eversource Energy, 1, 6/20/2022

- 0 - 0

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

- 0 - 0

Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #3.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

MidAmerican supports EEI’s comments and supports the SDT’s approach, which exempts units utilized for all periods except for the winter season, noting that the term “peaking” is not used in the Reliability Standard.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

- 0 - 0

Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

- 0 - 0

In regards to the proposed Section 4.2 Facilities definition:  In order to ensure a reliable response from generators that may be called upon by the Balancing Authorities during Capacity and Energy Emergencies, we recommend eliminating the exception for generators that do not operate during the winter season except when called upon by the Balancing Authority to be available during Capacity Emergencies or Energy Emergencies. Our recommended change to the language would be “The term excludes those generators that are not expected to operate during the winter season under normal and/or emergency conditions.”

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

- 0 - 0

SIGE is responding with “Yes”; however, SIGE does not currently have units identified for summer peaking purposes only.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

- 0 - 0

PPL NERC Registered Affiliates support EEI comments on Question 3. 

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

- 0 - 0

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

Nv Energy  supports EEI’s comments and supports the SDT’s approach, which exempts units utilized for all periods except for the winter season, noting that the term “peaking” is not used in the Reliability Standard.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

- 0 - 0

FirstEnergy agrees with EEI’s comments.  

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

- 0 - 0

Please see answer to question 2. If the GO can demonstrate via historical data or technical justification that it does not or can’t operate during a heightened cold weather event, some form of exemption should be available to avoid required must run mandate during cold weather-related energy emergencies. The standard must avoid forcing the closure of generation units from untenable compliance requirements. However, this should not relieve such Facility from winterizing plans to assure the generation units will not suffer damage rendering them unavailable upon return to warm weather conditions. Example: Generation unit is inaccessible during snow season road closure.

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

- 0 - 0

Portland General Electric Company supports the survey response provided by EEI.

PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

- 0 - 0

CEG suggests eliminating reference to winter and refer only to “intend to operate in cold weather”, the subject of the Standard.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

- 0 - 0

CEG suggests eliminating reference to winter and refer only to “intend to operate in cold weather”, the subject of the Standard.

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

- 0 - 0

I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

- 0 - 0

Calpine agrees that EOP-012-1 should only be applied to units that participate in the market during the winter season. This will limit costly winterization requirements to those resources that actually operate in the winter, alleviating any need for a resource that does not operate in the winter from undertaking costly measures that will not provide real benefits. Additionally, imposition of expensive winterization measures for resources that do not operate in the winter season could result in generators either retiring or opting out of the winter season entirely, potentially impacting reliability.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

CenterPoint Energy Houston Electric, LLC is not a registered Generator Owner or Generator Operator.

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

Although EGP agrees with the applicability of EOP-012-1, the language in the draft should be clarified.  The term "generating unit" in section 4.2 and throughout the draft standard causes confusion in how the standard applies to renewable resources.  Although an attempt to clarify is provided, the term generating unit refers to each and every individual turbine or invertor.  It is recommended to use the term "generating resource."  The term "generating resource" was adopted during the development of PRC-024 to resolve the same issue.

Natalie Johnson, Enel Green Power, 5, 6/21/2022

- 0 - 0

The SRC does not agree with the applicability of EOP-012 as drafted as NERC standards do not obligate a unit to declare their intent to operate by season. In addition, the Implementation Plan for this project provides anywhere from 18 months to 60 months (18 + 42 months) to comply with various requirements under the standard. The ability for a Generator Owner to alter its operability status during the “winter season” on an annual basis has the potential to negate the anticipated improvements that would be realized under this standard. Flexibility associated with applicability of the standard has the potential to reset the clock such that the improvements may never be realized. The SRC proposes the following language in replacement of the SDT proposed EOP-012-1 4.2 Facilities section: 

For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that plan or otherwise are obligated to be available to operate during the winter season, including Blackstart Resources, as determined by the Balancing Authority.  The winter season is defined as December through February unless the applicable Balancing Authority decides otherwise.  Each Generator Owner shall notify its applicable Balancing Authority if meeting the exemption to this section.

(Please note: ERCOT supports the SRC comments to Question #3 but does not agree with the proposed language in its entirety. ERCOT will provide separate comments to address this discrepancy.)

The SRC proposes this change since a number of RTOs/ISOs have obligated units which are deemed capacity resources to be available when called upon in emergencies irrespective of the particular season. The language as originally drafted would inadvertently tend to create unnecessary ambiguity as to those obligations by not requiring such units to be available if they don’t ‘plan to operate in the winter season’ (NOTE: Use exact language of original proposal). Section 215 (d)(6)of the Federal Power Act and FERC’s implementing rules note the need for harmonization of NERC Standards with RTO/ISO market rules and not work against RTO/ISO market rules.  The concern with the current proposed EOP-012-1 Applicability section: 4.2 Facilities is the exemption of certain units from having to winterize even if they have been designated as capacity resources to be called upon to operate to meet capacity emergencies.  The proposed language would fix this problem without changing the overall approach proposed by the authors. 

From the Joint Inquiry Report:

There are multiple references within “the Report” for BAs and RCs to be aware of specific generating unit limitations, such as ambient temperatures or fuel supply.”  The recently approved NERC Standards require the RC (IRO-010-4) and TOP and BA (TOP-003-5) to have provisions for notification from BES generating unit(s) to TOP and BA during local forecasted cold weather to include: Operating limitations based on: capability and availability; fuel supply and inventory concerns; fuel switching capabilities; and environmental constraints; and generating unit(s) minimum: design temperature; or historical operating temperature; or current cold weather performance temperature determined by an engineering analysis.  This GO cold weather data criteria was included in EOP-011-2, R7 and is now moved to EOP-013-1, R3 and is where GO cold weather preparedness plans now reside (per Project 2021-07).  However, the facility section of EOP-011-2 used the term “generating unit” to mean all BES generators and does not apply a generating unit exclusion as currently proposed in EOP-012-1.  Any generating unit taking the exclusion under the Facilities section of EOP-012-1 will not be subject to EOP-012-1 Requirements.  While the TOP may still request cold weather data (i.e. generating unit minimum operating temperature) per TOP-003-4 or TOP-003-5, the determination and evaluation by the generating unit may not serve as a basis to predict whether or not the unit will be able to perform during predicted cold weather if the unit is not performing the operating temperature limit analyses as well as related limitations, as defined in the EOP-012-1 Requirements.  Per ‘The Report’, “The Event demonstrated that ambient temperatures alone do not serve as a basis to predict whether a generating unit can perform during predicted cold weather.  For 81 percent of the generating units outaged, at the time the outage occurred, ambient temperatures were above the generating unit’s stated design criteria.”  The concern is the information communicated from the GO to the BA / TOP may be limited and unreliable if units are set to different methods of criteria in determining unit limitations. 

Per the Report: “TOP-003-5 R1 and R2 (effective April 1, 2023) will require TOPs and BAs, respectively, to include in their data specifications, to the GO, requests for information “during local forecasted cold weather” about generating units’ operating limits, including “capability and availability; fuel supply and inventory concerns; fuel switching capabilities; and environmental constraints,” as well as minimum temperature, based on one of three options. A related requirement, EOP-011-2 R7.3 (also effective April 1, 2023), will require GOs to develop cold weather preparedness plans which include, at a minimum, their generating unit(s)’ cold weather data such as the aforesaid capability, fuel supply concerns, environmental constraints, etc. The intent behind requiring GOs to identify and share with the BAs and TOPs the expected limitations of their generating units “during local forecasted cold weather, is to prevent grid operators from being surprised when large numbers of generating units that had committed to run are unable to do so during cold weather events.”  This exchange of accurate generator unit operating limitations will be limited by those generating units no longer subject to a cold weather preparedness and may result in TOPs and BAs not being provided the correct operating limits in performing Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.  By removing the unit exemption in EOP-012-1, the unit will perform the operating limitation analysis that meets the current Standard (EOP-011-2, effective April 2023 and newly proposed EOP-012-1) and allows for accurate TOP/BA assessments in preparing and operating in cold weather conditions.

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

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Q3. ERCOT suggests the applicability language for facilities in Section 4.1.2 be revised as shown below.  “Plan to operate” is not sufficiently clear, as neither the Regional Entity nor the BA, RC, or PC can know the GO’s subjective intentions.  Accordingly, the BA should decide not only how winter should be defined for the BA Area, but also whether a generating unit is obligated to be available under the relevant rules.  To the extent the SDT determines that the BA’s responsibility to identify units that are covered by the standard should be stated more explicitly within the requirements, ERCOT would support that change.

ALTERNATE LANGUAGE PROPOSED:

For purposes of this standard, the term “generating unit” means those Bulk Electric System generators that plan, or otherwise are obligated, to be available to operate during the winter season, including Blackstart Resources, as determined by the Balancing Authority.  The winter season is defined as December through February unless the applicable Balancing Authority decides otherwise.  A list of those units exempt from this standard for a given winter season shall be maintained by the Balancing Authority.

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

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Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

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LCRA generally agrees with the concept on exemptions for summer run only units. Typically, penalization of unit operation is related to market rules. Therefore, penalties should not be considered under NERC jurisdiction. However, if this becomes a NERC requirement, this could unfairly subject an entity to double jeopardy.

Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

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LCRA generally agrees with the concept on exemptions for summer run only units. Typically, penalization of unit operation is related to market rules. Therefore, penalties should not be considered under NERC jurisdiction. However, if this becomes a NERC requirement, this could unfairly subject an entity to double jeopardy.

James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

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Hot Answers

TransAlta understands the challenges the STD has associated with developing appropriate risk based standards to deal with the effects of extreme weather on the grid. TransAlta respectfully provides the following feedback:

The proposed language in EOP-012-1 requirement R1 does raise significant concerns. Facilities in particularly cold climates, such as Canada, would have significant freeze protection measures in place which means they do successfully operate in extremely cold conditions year after year. This standard presents us with the administrative burden of documenting and maintaining that documentation to describe basic facts about our facility as it relates to freeze protection measures with no benefit to the reliability of the grid in those regions.

TransAlta also supports comments made by NRG Energy and NPCC Regional Standards Committee  with regard to this question.

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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JEA believes that continuous operations at a single recorded temperature will be a significant undertaking (cost, manpower, active maintenance & associated risks) without much benefit in Jacksonville, FL. Our lowest temperature was in 1985 at 7 degrees F for two hours, but our mean low for December, January, and February is 28, 25, and 28 degrees F. To operate for 7 degrees F continually even during the winter season will place a strain on resources, requiring heat tape where insulation would be sufficient (based upon a conservative forecast).

Some exclusion for regions that experience minimal freezes should be considered. For example, “If hourly temperature data shows that the entity experienced less than 10 five-hour freezes in the past five years, continuous operation at the minimum temperature is not required.” This is a suggestion, but a suitable expert could be consulted to suggest a time element (X-hour freezes) with a suitable number of cases (Y instances) over a recent time period (past Z years).

John Babik, JEA, 5, 6/21/2022

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Other Answers

Idaho Power is proposing the following language modification due to the fact that manufacturers do not provide design data. Propose in R1.1-1.3: Each generating unit shall be capable of continuous operations either by design data or by operational data documented minimum hourly temperature.

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

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No issues with the requirements.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

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 The proposed language does not provide a formula for determining minimum hourly temperature. Is this minimum instantaneous temperature or integrated minimum temperature over a period of time? 

In addition, the new language requires continuous operation but ability to start-up under minimum temperature conditions is left unaddressed or implied. Specific language regarding ability to start-up should be considered for R1.1 in addition to start up failures described in R6.    

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

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For some Canadian entites, units already operate in cold weather annually from November to March. These requirements represent an added administrative burden.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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R1 – 1.1 appears to require us to monitor the temperature at each of our facilities and to review that data from 1/1/1975 to current. Most of our facilities, especially our hydro facilities do not monitor the air temperature or wind speed at our plants. For compliance with EOP 11-2 we intend to use the national weather service at a nearby airport (Spokane) to represent the temperature of the plants in our region. The farthest plant from this datum is about 120 miles from the Spokane airport NOAA station. We believe that the national weather service is a much more credible source of forecasting and monitoring temperatures in our area than our own gauges would be. Does the NERC assume that to comply with EOP 12-2, R1.1 and R3.1 that all plants will now be required to install temperature monitoring at our sites, perform compliance calibrations and certifications on such temperature monitoring equipment, and use our own temperature monitoring equipment at each site to monitor for compliance notification protocols associated with TOP 3-5 and IRO 10-3 to satisfy this standard? If so, this seems unreasonable. To comply with EOP 11-2 our current draft plans for cold weather notifications for EOP 11-2, TOP 3-5 and IRO 10-3 are to use the regional airport temperature from NOAA as our gauge for weather forecasting for all our plants in the area. We have one system operations office that will among many other things, monitor the temperature in the region (if necessary) and perform appropriate callouts to plants proactively, before the temp gets to or below the extreme historical minimum notifying them of extreme cold weather may be on the way at or before the cold weather is experienced at each plant. We believe if we must monitor multiple temperature monitoring sites across our region (at each site, or at a separate datum like regional airports near each plant) we will burden the operations teams with many more activities and calls during a cold weather event. This could lead to many more latent errors, missed steps, completing too many tasks to accurately monitor the operation of the system during an emergency event, and we believe that this would go beyond the intent of the Cold Weather Standard, and/or the report recommendations. Can you please clarify in EOP 12-1 R1.1 and R3.1 if it is acceptable to monitor a regional third-party temperature sensor (Such as NOAA) for compliance with EOP 12-1 for a group of facilities if the temperature monitoring equipment is within 150 miles of each facility?

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

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Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

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Installing freeze protection is redundant in many cases and in some case may not even be applicable, not to mention the excessive cost to modify or implement new measures. 

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

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The year 1975 pre-dates modern weather forecasting and recording capabilities. If desired to extend the monitoring period to that extent, we suggest that the requirement instead specify the minimum hourly temperature at the nearest National Weather Service location.  

Existing generating units should be required to analyze their designed operation parameters using the freeze protection factors to identify any cold weather limitations based on historic operations dating back to 1975, then develop a time limited Corrective Action Plan.   

Requirement 1 is an overreach of the Federal Power Act because it requires existing facilities to add equipment or retrofit its facilities.  

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

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Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

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NRG has several concerns related to this requirement:

A)     NRG agrees with NAGF’s comment that the SDT is not following NERC’s stated Market Principals, which exist for a reason. NERC needs to address the conflict between the proposed requirement and the Market Principle which states “Standards shall not define an adequate amount of, or require expansion of, bulk power system resources or delivery capability.” By requiring generators to improve their capability to withstand extreme weather beyond the current design, they are requiring expansion of the delivery capability. This proposed requirement also appears to conflict with NERC’s Market Principal “A reliability standard shall not give any market participant an unfair competitive advantage.” As long as some market participants are able to pass the costs associated with retrofitting units through to rate payers and other market participants are not able to pass the costs through to the end users, the proposal to require retrofits will provide some market participants advantages over others.  Has the SDT taken this into account and, if so, how are they addressing the concern?

B)      NRG also agrees with the NAGF to support the desire to allow the Transmission Planners, Balancing Authorities, Transmission Operators and Reliability Coordinators to better predict the point where extreme weather may cause problems, but this requirement does not do that.  Instead, this requirement puts the onus on generators to be able to operate through any cold weather event, regardless of the existing capability or limits, including potentially more restrictive limits on Transmission, Distribution, and fuel delivery.

C)      NRG generally agrees that, ideally, minimum operating temperatures need to include effects of wind chill and precipitation when defining unit limitations. However, NRG does not agree with using the one-hour min historical operating temperature as the criterion for basing all freeze protection measures for all plant systems. The one-hour criterion is much more conservative, and the probability of this occurring is extremely small yet much more costly to implement. This criterion is not practical and not based upon a technically based industry design standard for freeze protection.  The SDT should consider ASHRE, a statistically based standard which uses daily average temperatures, which has been accepted and used by industry for many years.  It is also not consistent with other regulatory bodies rulings such as the PUCT draft ruling (which uses the lesser of the min ambient operation at which the resource has experienced sustained operation or the ASHRE 95% min average 72-hour temp reported in the ERCOT historical study). Finally, overdesigned cold weather protection will reduce hot weather reliability. Without practical limit to winter preparation, summer reliability may subsequently be reduced.

D)    NRG also has concerns that retrofitting existing units to the same design standard as new units will also be costly and lengthy to implement.  Focus should be on Freeze protection measures, not full retrofits/redesign, and should address only those critical components that could potentially trip/derate the unit. Root cause analysis of previous freeze-related outages have not revealed concerns for auxiliary systems that support operation but are considered part of balance-of-plant. These can be addressed through sound operational practices and startup prior to freeze events. In summary, retrofits of existing units should not include all operating systems and should not be required without some cost recovery realized.

E)  NRG agrees with NAGF’s comments that most engineering processes do not attempt to create 100 percent reliability, simply because it is impossible to achieve. This is true for generator design to meet expected temperatures. Traditionally, generation was designed to meet some level of expectation below 100 percent.

 

For these reasons, NRG cannot recommend support for this requirement until the issues identified here are adequately addressed by the SDT.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

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The IESO requests removing the ‘commercial’ reference in Requirements 1.4.2 and 1.4.4 as this language is vague, creates an ambiguity as to the obligation otherwise provided for in the standard, and a review of commercial issues is not within NERC’s domain and expertise.

 

1.4.2. A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical or operational constraints, as defined by the Generator Owner;

1.4.3. An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

1.4.4. A declaration, where deemed appropriate by the Generator Owner    based on the review of Parts 1.4.1 through 1.4.3, that no revisions to the cold weather preparedness plan(s) are required and that no further corrective actions will be taken. The Generator Owner shall document technical or operational constraints as defined by the Generator Owner as support for such declaration.

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

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BPA supports the comments submitted by the US Bureau of Reclamation.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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The cold weather preparedness plan(s) required by EOP-012-1 R3.2 include freeze protection measures be taken. The proposed Requirement R1 appears redundant to R3.2 and should be removed from the proposed revision. 

 

The difference between the temperature requirement in R1.1 and that of the stated minimum unit temperature in R3.4.2 has the potential to be significant and working towards operating at the lowest of the two will possibly, in many cases, be too cost prohibitive and therefore will likely cause many entities to claim this declaration under R1.4.4.

 

For nuclear plants, the temperature band is built into both the design and licensing basis of the plant.  Changing the analysis is neither cost effective nor prudent. The NERC required temperature bands in excess of what NRC requires for safety of the plant is prohibitive of economic, cost effective operation.

 

As an example, the NRC Updated Safety Analysis Report (USAR) for one particular nuclear plant states that the plant is designed for a low temperature of -5° F dry bulb, which will only be exceeded 1% of the time during the winter. If -5° F is exceed a condition report is generated to allow tracking of the amount of time the temperature is exceeded. Per the 1972 ASHRAE Handbook of Fundamentals, the winter is considered to be December, January, and February, which amounts to 2160 hours each year. The design value of -5° F was taken from the same 1972 ASHRAE Handbook for a location geographically close to the plant, which substantiates the statement in the USAR that the design maximum and minimum temperatures will be exceeded approximately 1% of the time during a normal winter.  To verify the operating conditions for this plant meet this statement a cumulative percentage was determined for winter months for the period of July 2004 to March 21, 2022.  These results show the design low temperature is exceeded only .49% of the time during the winter.

 

Based on the extensive design analysis performed at nuclear generating facilities and ongoing trending that occurs each winter to ensure they are bounded by the analysis, it doesn’t seem practical to change the entire design/licensing basis of the plants to match the minimum hourly temperature experienced since 1/1/1975. This proposed NERC requirement is in conflict with the NRC Requirement.

 

Additionally, the design requirements for line and structure strength are based on wind speeds and radial ice formation less than the historical maximums experienced at the line locations. Construction of a power line designed to withstand the conditions experienced in a hurricane or tornado would be unreasonably cost prohibitive.

 

Consideration of temperature data back to 1/1/1975 seems excessive and does not correlate to NERC compliance history. We recommend the scope of study required by R1.1 and R3.1 be changed from 1/1/1975 to 6/18/2007. NERC requirements cannot create requirements prior to the enforcement date of June 18, 2007 there is no legal authority.

 

Recommendation: 

a) Change the lookback date for coldest temperature to 6/18/07

b) Implement a standardized statistical approach for all BES generators be taken to have a more realistic method than identifying the lowest value seen since the specified lookback date

c) Include an exemption in Section 4.2 Facilities for nuclear generation based on the extensive design basis analysis that has already been completed

d) Change verbiage of Requirement R1. “Each Generator Owner shall plan to implement freeze protection measures on generating units based on the following minimum criteria: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]”

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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NRG has numerous concerns related to this requirement:

A.)  NRG agrees with NAGF’s comment that the SDT is not following NERC’s stated Market Principals, which exist for a reason. NERC needs to address the conflict between the proposed requirement and the Market Principle which states “Standards shall not define an adequate amount of, or require expansion of, bulk power system resources or delivery capability.” By requiring generators to improve their capability to withstand extreme weather beyond the current design, they are requiring expansion of the delivery capability. This proposed requirement also appears to conflict with NERC’s Market Principal “A reliability standard shall not give any market participant an unfair competitive advantage.” As long as some market participants are able to pass the costs associated with retrofitting units through to rate payers and other market participants are not able to pass the costs through to the end users, the proposal to require retrofits will provide some market participants advantages over others.  Has the SDT taken this into account and, if so, how are they addressing the concern?

B).  NRG also agrees with the NAGF to support the desire to allow the Transmission Planners, Balancing Authorities, Transmission Operators and Reliability Coordinators to better predict the point where extreme weather may cause problems, but this requirement does not do that.  Instead, this requirement puts the onus on generators to be able to operate through any cold weather event, regardless of the existing capability or limits, including potentially more restrictive limits on Transmission, Distribution, and fuel delivery.

C.)      NRG generally agrees that, ideally, minimum operating temperatures need to include effects of wind chill and precipitation when defining unit limitations. However, NRG does not agree with using the one-hour min historical operating temperature as the criterion for basing all freeze protection measures for all plant systems. The one-hour criterion is much more conservative, and the probability of this occurring is extremely small yet much more costly to implement. This criterion is not practical and not based upon a technically based industry design standard for freeze protection.  The SDT should consider ASHRE, a statistically based standard which uses daily average temperatures, which has been accepted and used by industry for many years.  The criterion is also not consistent with other regulatory body rulings such as the PUCT draft ruling (which uses the lesser of the min ambient operation at which the resource has experienced sustained operation or the ASHRE 95% min average 72-hour temp reported in the ERCOT historical study). Finally, overdesigned cold weather protection will reduce hot weather reliability. Without practical limits to winter preparation, summer reliability may subsequently be reduced.

D.) NRG also has concerns that retrofitting existing units to the same design standard as new units will also be costly and lengthy to implement.  Focus should be on freeze protection measures, not full retrofits/redesign, and should address only those critical components that could potentially trip/derate the unit. Root cause analyses of previous freeze-related outages have not revealed concerns for auxiliary systems that support operation but are considered part of balance-of-plant. These can be addressed through sound operational practices and startup prior to freeze events. In summary, retrofits of existing units should not include all operating systems and should not be required without some cost recovery realized.

E.)      NRG agrees with NAGF’s comments that most engineering processes do not attempt to create 100 percent reliability, simply because it is impossible to achieve. This is true for generator design to meet expected temperatures. Traditionally, generation was designed to meet some level of expectation below 100 percent.

 

For these reasons, NRG cannot recommend support for this requirement until the issues identified here are adequately addressed by the SDT.

 

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

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BC Hydro appreciates the opportunity to comment and has the following comment seeking to confirm our understanding against the intent of Requirement R1 of proposed EOP-012-1 (Draft 1) as follows. Following an assessment of the existing generating units’ freeze protection, if determined that the freeze protection measure are adequate and meet the criteria set out in Requirement R1 of proposed EOP-012-1, then there would be no need to “implement new freeze protection measures or modification of existing freeze protection measures”, i.e. no Corrective Action Plan will be required per Requirement R1 Part 1.4.

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Dominion Energy supports continued cold weather measures being taken for existing generators to meet their designed operating specifications in extreme cold weather. Dominion Energy supports both the EEI and NATF comments that both the FPA Section 215 of 2005 and NERC’s own market principles preclude a retrofit requirement for existing generators to meet a design specification universally. The Federal Power Act Section 215 definition of “Reliability Standard” states in relevant part that the term includes requirements for “the design of planned additions or modifications to such facilities to the extent necessary to provide for reliable operation of the bulk power system….”  This phrase suggests that reliability standards cannot have requirements that require unplanned modifications.  Dominion Energy supports EEI’s suggestion that the standard drafting team ask NERC to provide a legal memorandum on whether Section 215 of the Federal Power Act allows a Reliability Standard to require existing generating units to be redesigned or otherwise modified to meet certain freeze protection requirements beyond their original design as set forth in Requirement R1. 

Additionally, the requirements to make modifications to existing resources to expand their capability may not be a recoverable expense for generator owners. 

 

Additionally, we support two separate requirements, 1) that addresses new generating resources installed on or after the effective date of the Standard and; 2) those generating units that were installed prior to the effective date of the Standard to proactively maintain existing system to ensure the reliable operation of the BES.   

 

 

R2 for Existing Generating Units installed prior to the effective date of EOP-012-1:

R2.    Each Generator Owner who owns generating units that were placed into commercial operation prior to the effective date of the Standard shall:that is not able to implement freeze protection measures for new generating unit(s) as required by Requirement R1 due to technical, commercial, or operational constraints as defined by the Generator Owner shall: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning]

{C}2.1.       {C}Document its determination and the constraints on implementation; and Identify the operational capability of the generating units and supporting auxiliary systems, within the cold weather criteria identified in Requirement R1, subparts 1.1 and 1.2, through one of the following methods:

2.1.1  Report the designed operational capability as specified by the OEM within the identified cold whether criteria to their responsible GOP and BA; or

2.1.2  Calculate the expected operational capability through either an engineering analysis of available unit data or an assessment of the unit’s performance since its commercial operation date, not exceeding a period of twenty years and report it to their responsible GOP and BA.  Review its determination every five calendar years to determine whether the documented constraints on implementation remain applicable.

2.2   Report all generating units that are not designed (2.1.1) or do not have the evaluated capability (2.1.2) to reliably operate at their rated capacity over the full range of the cold weather criteria to their responsible GOP and BA.

{C}2.3    Report the expected cold weather operating capability of each of its generating units to their responsible GOP and BA. 

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Concerns include:

1.‘Designed and maintained’ and ‘continuous operation’ are not measurable requirements.

Propose this language for R1.1: The generating unit(s) design shall be based on the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975;

2.      R1.4 as written should be separated into multiple Requirements and not part of 1.1 as follows:

 

2              Each Generator Owner that determines their generating unit(s)  require either new freeze protection measures or modification of existing freeze protection measures pursuant to R1, the Generator Owner shall develop and implement a Corrective Action Plan (CAP) which includes the following at a minimum:

2.1  An identification of corrective action (s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

2.1  A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;

2.1  An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP

3. If the Generator Owner determines, that no revisions to the cold weather preparedness plan(s) are required and that no further corrective actions will be taken based on the review of Parts 1.1.1 through 1.1.3, the Generator Owner shall document technical, commercial, or operational constraints as defined by the Generator Owner as support for such determination.

 

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

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DTE Electric supports NAGF comments.Please see NAGF proposed language.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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"At it's location" may be too ambiguous and doesn't represent enough specificity to accurately define weather conditions.  The FERC report also references the nearest city.  What constitutes the nearest city?  The nearest city may not be indicative of the local weather.

 

Suggested Edit:

"A NOAA established location within 25 miles. NOAA data is a default. To use another documented method, justification would need to be provided as to why it is needed or why it is superior to NOAA.  Alternative temperature data shall be described in the applicable cold weather preparedness plan.”

This could also be more detailed in Requirement 3.1 which defines areas that are covered in the cold weather preparedness plan.

Suggest Revising:

R3.1 Documented minimum hourly temperature experienced at a NOAA or Environment and Climate Change (for generating units located in Canada) established location within 25 miles of its location since 1/1/1975 or a lesser period if data is not available.

            R3.1.1 Justification for the use of alternative temperature data if NOAA data is unavailable or another source of temperature data is used to determine the minimum temperature

Other concerns are for Commercial Constraints.  Will this be interpreted as “too expensive”?  Does this clause render the entire Standard moot for anyone that doesn’t want to spend the money to upgrade the facilities?  Are there any other references in the NERC Standards that allow entities to opt out due to commercial constraints?  For example: FAC-003 does not allow for skipping tree trimming due to cost.  What will the oversight process be for generators that declare they are unable to implement freeze protection?  See ISO—NE Concerns in Question 3.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

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EOP-012-1 is unclear and confusing because of disorganized language and grammatical errors, some of which have perpetuated from EOP-011-2. For example, generating units do not implement anything. Many pieces of equipment do not “freeze,” i.e., solid metal is already “frozen” by definition. Rather, equipment fails due to improper protection from extreme cold. The requirements should be stated so that the registered entity, e.g., the Generator Owner, is the one implementing the action. Distinct obligations should be contained in separate requirements, not combined at the requirement part and sub-part levels. Reclamation recommends using active voice throughout the standard to clearly state the requirements.

Reclamation recommends rewriting the requirements of EOP-012-1 as follows:

R1. *use existing language from Draft 1 EOP-012-1 R1.1* with the following corrections:

Each Generator Owner shall design new and maintain existing generating units to be capable of continuous operations at the documented minimum hourly temperature experienced at each unit’s location since 1/1/1975 or a lesser period if reliable data is not available to 1975.

R2. *use existing language from Draft 1 EOP-012-1 R1* with the following corrections:

Each Generator Owner shall implement new or modify existing protection based on the documented minimum hourly temperature for its generating units including the following minimum criteria:

R2.1. the cooling effect of wind; and

R2.2. impacts on equipment operation due to precipitation (e.g., sleet, snow, ice, and freezing rain).

R3. *use existing language from Draft 1 EOP-012-1 R1.4* with the following corrections:

For each existing generating unit that requires new or modified protection based on the documented minimum hourly temperature, the Generator Owner shall develop and implement a Corrective Action Plan (CAP) or, where deemed appropriate by the Generator Owner based on the review of parts R3.1.1 through R3.1.3., declare that no corrective actions will be taken.

R3.1. A CAP shall contain the following minimum information:

R3.1.1. Corrective action(s) for the affected unit(s).

R3.1.2. Any temporary operating limitations that would apply until the corrective actions are implemented.

R3.1.3. A schedule for implementing the corrective action(s).

R3.2. A declaration shall document any technical, commercial, or operational constraints of each affected unit, as defined by the Generator Owner, in support of the declaration.

R4. *use existing language from Draft 1 EOP-012-1 R2* with the following corrections:

Each Generator Owner that does not implement new or modify existing protection based on the documented minimum hourly temperature in accordance with R2 due to technical, commercial, or operational constraints, as defined by the Generator Owner, shall:

R4.1. Document its determination and the constraints; and

R4.2. Review its determination every five calendar years to determine whether the constraints remain applicable.

R5. *use existing language from Draft 1 EOP-012-1 R3*

R6. *use existing language from Draft 1 EOP-012-1 R4, update Part numbers as necessary*

R7. *use existing language from Draft 1 EOP-012-1 R5* with the following corrections:

Each Generator Owner, in conjunction with its Generator Operator, shall ensure generating unit-specific cold weather preparedness plan training is provided to its personnel responsible for implementing cold weather preparedness plans.

R7.1. The Generator Owner and Generator Operator shall identify the entity responsible for providing the training.

R7.2. The Generator Owner and Generator Operator shall ensure the training is provided to personnel responsible for implementing cold weather preparedness plans upon entrance on duty and annually thereafter.

R8. *use existing language from Draft 1 EOP-012-1 R6* with the following corrections:

Each Generator Owner that owns a generating unit that experiences an event resulting in a derate of more than 10% of the total capacity of the unit for longer than four hours in duration, a start-up failure where the unit fails to synchronize within a specified start-up time, or a Forced Outage for which (i) the apparent cause(s) of the event is due to extreme cold weather effects within the Generator Owner’s control to protect against, and (ii) the ambient conditions at the site at the time of the event are at or above the temperature documented in Part 3.4.2 shall:

R8.1. No later than 150 days subsequent to the event or by July 1 that follows the event, whichever is later, develop a CAP; or

R8.2. Declare, where deemed appropriate by the Generator Owner based on review of Parts 8.3.1. through 8.3.5, that no revisions to the cold weather preparedness plan are required and that no further corrective actions will be taken.

R8.3. At a minimum, a CAP shall contain:

R8.3.1. A summary of the identified cause(s) of the equipment derate, failure to start, or Forced Outage, and any relevant associated data.

8.3.2 use existing 6.2.1. language

8.3.3. use existing 6.2.2. language

8.3.4. (modified 6.2.3.) Specific corrective action(s) for the affected unit(s) and identified similar units, including:

8.3.4.1. (modified 6.2.3.) any necessary modifications to the Generator Owner’s cold weather preparedness plan(s); and

8.3.4.2. (modified 6.2.4.) consideration of any technical, commercial, or operational constraints, as defined by the Generator Owner.

8.3.5. A schedule for implementing the corrective actions.

R8.4. At a minimum, a declaration shall document technical, commercial, or operational constraints, as defined by the Generator Owner, as support for the declaration.

Reclamation recommends the timeframe for developing a CAP be 150 days subsequent to the event or by July 1 that follows the event, whichever is later. Using whichever is earlier could subject an entity to an unreasonably short deadline depending on when the event occurs.

Reclamation recommends moving the language pertaining to the cold weather preparedness plans from the original R1 to the original R3 (new R5 based on Reclamation’s proposed renumbering in the above comments). Modifications to the cold weather preparedness plan should relate back to the CAP, if necessary, not the CAP requirements relating forward to the cold weather preparedness plan.

Reclamation recommends not limiting the training on cold weather preparedness plans to “maintenance or operations” personnel, as other personnel may also be responsible for implementing cold weather preparedness plans and should not be excluded from the training. Reclamation recommends the annual cold weather preparedness plan training be contained in PER-006 instead of EOP-012.

Reclamation supports the retention and reuse of pertinent information from the Draft 1 Measures.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

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Claudine Bates, Black Hills Corporation, 6, 6/16/2022

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WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

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we support the RSC comments.

For some Canadian entites, units already operate in cold weather annually from November to March. These requirements represent an added administrative burden.

The new reliability standards requirement should be part of a regional variance for the regions where winterization programs are not in place. Canadian entities generators already operate successfully in cold climate with extreme conditions. For such entities this is an additional compliance burden, with no additional benefit to grid reliability.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

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Tacoma Power is concerned that the proposed language in EOP-012-1 R1, as well as Parts 3.1 and 4.1, places significant administrative and analytical burden on entities, and potentially complicates the assessment of design capabilities. Tacoma Power is concerned that collecting and maintaining hourly temperature data would amount to finding a needle in a haystack (over 400,000 data points in a 50 year time period). Instead, Tacoma Power recommends utilizing annual temperature data to identify the lowest temperature recorded for the year. This approach results in a smaller set of data to maintain and is easier for entities to identify the lowest temperature needed for freeze protection. Additionally, analyzing hourly data from summer periods is not beneficial, so a lowest recorded temperature for the year is more appropriate.

Tacoma Power recommends modifying Part 1.1, Part 3.1 and Part 4.1 to remove the Requirement for a specific interval, and only require documentation of the lowest recorded temperature since 1975, as follows. This change allows an entity to determine whether hourly, daily or annual is the most appropriate for their assessments.

Recommended changes to Parts 1.1, 3.1 and 4.1:

  • Part 1.1: “Each generating unit shall be designed and maintained to be capable of continuous operations at the lowest recorded ambient temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.”
  • Part 3.1: “Lowest recorded ambient temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975;”
  • Part 4.1: “Review the lowest recorded ambient temperature developed pursuant to Part 3.1, and update the cold weather preparedness plan with the lowest temperature as necessary.”

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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PG&E supports the comments provided by the Edison Electric Institute (EEI) and the North American Generators Forum (NAGF).  In addition, PG&E has the following comments:

PG&E representatives attended the April 27th and 28th, 2022 FERC\NERC technical conference on cold weather.  Listening to all of the testimony from utilities in New Mexico, Texas, and the South and Eastern United States representing GO's and GOP's, ISO's, and Natural Gas Distributors, it became apparent to PG&E that utilities across the USA have taken corrective actions to harden their generating units from cold weather.  PG&E contends that EOP-012-1 is not required and believes that utilities that have had historical operating problems during cold weather events have already implemented cold weather plans/checklists and equipment upgrades that follow the FERC recommendations.  EOP-012-1 will make warm-weather utilities perform expensive analysis, training, and design changes that are not commensurate with grid reliability and risk reduction.  In the PG&E California portfolio, we have numerous plants that historically have never experienced below-freezing temperatures for extended periods.  In addition, numerous GO's in the western part of North America have an extremely low probability of experiencing sub-freezing temperatures.  With this new standard, GO's are being required to develop a cold weather plan, train the operating staff, and implement design changes that do not benefit operational reliability or grid reliability.  PG&E believes the current EOP-011-1 meets the intent of the FERC recommendations.  If EOP-012-1 continues to be developed and later approved, PG&E recommends an allowance (exemption) within the Standard that those GO's who can prove their lowest hourly temperature is above freezing, the Standard should clearly state that those GO's are exempted from EOP-012-1.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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Texas RE does not have comments on this question.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

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NCPA, Segment(s) 4, 5, 6, 4/3/2020

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Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

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AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

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NCPA agrees with the comments of NRG Energy, Inc.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

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Southern Company supports the EEI comments and would add that the declarations of technical, commercial, or operational constraints by the GO that limit operational capability should, at minimum, be communicated to their applicable BA and RC to prevent the creation of an avenue for avoidance of availability that would limit the generation being available to the BA during extreme cold weather events.

 

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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See comments provided in separate Word documents.

Mark Young, Tenaska, Inc., 5, 6/16/2022

EOP-012 Comments - Tenaska Final.docx

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R1 – 1.1 appears to require us to monitor the temperature at each of our facilities and to review that data from 1/1/1975 to current. Most of our facilities, especially our hydro facilities do not monitor the air temperature or wind speed at our plants. For compliance with EOP 11-2 we intend to use the national weather service at a nearby airport (Spokane) to represent the temperature of the plants in our region. The farthest plant from this datum is about 120 miles from the Spokane airport NOAA station. We believe that the national weather service is a much more credible source of forecasting and monitoring temperatures in our area than our own gauges would be. Does the NERC assume that to comply with EOP 12-2, R1.1 and R3.1 that all plants will now be required to install temperature monitoring at our sites, perform compliance calibrations and certifications on such temperature monitoring equipment, and use our own temperature monitoring equipment at each site to monitor for compliance notification protocols associated with TOP 3-5 and IRO 10-3 to satisfy this standard? If so, this seems unreasonable. To comply with EOP 11-2 our current draft plans for cold weather notifications for EOP 11-2, TOP 3-5 and IRO 10-3 are to use the regional airport temperature from NOAA as our gauge for weather forecasting for all our plants in the area. We have one system operations office that will among many other things, monitor the temperature in the region (if necessary) and perform appropriate callouts to plants proactively, before the temp gets to or below the extreme historical minimum notifying them of extreme cold weather may be on the way at or before the cold weather is experienced at each plant. We believe if we must monitor multiple temperature monitoring sites across our region (at each site, or at a separate datum like regional airports near each plant) we will burden the operations teams with many more activities and calls during a cold weather event. This could lead to many more latent errors, missed steps, completing too many tasks to accurately monitor the operation of the system during an emergency event, and we believe that this would go beyond the intent of the Cold Weather Standard, and/or the report recommendations. Can you please clarify in EOP 12-1 R1.1 and R3.1 if it is acceptable to monitor a regional third-party temperature sensor (Such as NOAA) for compliance with EOP 12-1 for a group of facilities if the temperature monitoring equipment is within 150 miles of each facility?

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

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NCPA agrees with the comments of NRG Energy, Inc.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

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AEP does not agree that R1 should specify that generating units must be redesigned to meet freeze protection requirements.  Instead, R1 should require generating units to have the *ability* to continuously operate within an identified operating range, with the methods on how this is accomplished determined solely by the owner. Many actions can and have been taken to ensure units operate successfully through the winter that would not impact unit design (such as temporary enclosures and temporary heat sources).

AEP suggests that R1 be revised so that the wind and precipitation requirements contained in subparts 1.2 and R 1.3 are incorporated into subpart 1.1.  The considerations for wind versus precipitation are not always unique and are typically all considered at the same time when systems are reviewed for cold weather operability which is required by R 1.1. As a result, separate sections are not warranted in the standard.

Requirement 1.4.4 allows for the Generator Owner to make a declaration of no action due to technical, commercial, or operational constraints, which infers that the Generator Owner is able to establish the criteria regarding the resulting exemption. AEP agrees with this concept, but suggests that the additional clarity be provided within the standard to make it clear that such a declaration, and the decision making which drives it, is solely at the discretion of the Generator Owner.

AEP supports the comments made by EEI in response to this question.

Thomas Foltz, AEP, 5, 6/17/2022

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Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

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Yes, we have concern and want to ensure GO requirements will align with the BA. Using coldest data information since 1975 does have concern, as the GO still won’t be able to document all applicable temp/wind/moisture/etc. facts that impact reality.  The requirement should only specify the minimum hourly temperature at the nearest National Weather Service location that plant has successfully operated. 

Existing generating units should only be required to analyze their designed operation parameters using freeze data and any cold weather limitations based on historic operations dating back to 1975, with defined interval(s) of operation.  

Glenn Pressler, CPS Energy, 3, 6/17/2022

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Invenergy has the following concerns and suggestions about the proposed language:

(1)   Invenergy supports the retention of the “commercial, technical, or operational constraints” clause in R1, and would be concerned if it were removed.

(2)   Invenergy is concerned about the temperature criteria used in R1.1, which relies on an arbitrary historical temperature start date of 1/1/1975 along with a single minimum hourly temperature.  Together, these two parameters create an arbitrarily stringent standard that could impose more onerous design and maintenance requirements than are necessary to ensure generator availability during the prolonged extreme cold events – occurring over multiple hours or days – that this Standard is intended to address. As but one example, the minimum historical hourly temperature at a given location might be in the middle of the night, but it would not be reasonable to design a solar generator to meet that criterion. Instead, Invenergy suggests the SDT explore alternative methodologies to generate design and maintenance parameters that are targeted to ensuring generator availability during the extreme cold events this Standard seeks to address. For example, and without endorsing the specific parameters used or the resulting proposed requirements, Invenergy notes that the Public Utility Commission of Texas has an open docket (Project No. 53401, Electric Weather Preparedness Standards-Phase II) to set weather preparedness standards.  In that proceeding, the Commission Staff proposed (Memorandum and Proposal for Publication dated May 19, 2022), among other items, a standard of “…the lesser of the minimum ambient temperature at which the resource has experience sustained operations or the 95th percentile minimum average 72-hour temperature reported in ERCOT’s historical weather study…for the weather zone in which the resource is located.” (Emphasis added.)  The use of a multi-day average temperature with a percentile rather than the single coldest hour better targets the events the Standard is intended to address. The specific parameters (how many hours or days, which percentile, which zones, and other criteria) could be developed as part of the SDT’s process.

(3)   Invenergy recommends striking “continuous” from R1.1. to be more inclusive of all generation types, such as wind and solar generation output, which is variable, not continuous.

(4)   Invenergy suggests the following modifications to R1.4 to clarify Generation Owners declaring a commercial, technical, or operational constraint are not required to develop and implement a Corrective Action Plan:

 

1.4. For each existing generating unit that requires either new freeze protection measures or modification of existing freeze protection measures to meet the requirements of 1.1, 1.2, or 1.3, the Generator Owner shall do one of the following:

1.4.1. Develop and implement a Corrective Action Plan (CAP) that includes the following at a minimum:

1.4.1.1. An identification of corrective action(s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

1.4.1.2. A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;

1.4.1.3. An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; OR

1.4.2. Submit a declaration that the implementation or modification of freeze protection measures for existing generating unit(s) as required by Requirement R1 is not possible due to technical, commercial, or operational constraints as defined by the Generator Owner, and that no further corrective actions will be taken. The Generator Owner shall document technical, commercial, or operational constraints as defined by the Generator Owner as support for such declaration.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

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Invenergy has the following concerns and suggestions about the proposed language: 

 

(1) Invenergy supports the retention of the “commercial, technical, or operational constraints” clause in R1, and would be concerned if it were removed. 

(2) Invenergy is concerned about the temperature criteria used in R1.1, which relies on an arbitrary historical temperature start date of 1/1/1975 along with a single minimum hourly temperature.  Together, these two parameters create an arbitrarily stringent standard that could impose more onerous design and maintenance requirements than are necessary to ensure generator availability during the prolonged extreme cold events – occurring over multiple hours or days – that this Standard is intended to address. As but one example, the minimum historical hourly temperature at a given location might be in the middle of the night, but it would not be reasonable to design a solar generator to meet that criterion. Instead, Invenergy suggests the SDT explore alternative methodologies to generate design and maintenance parameters that are targeted to ensuring generator availability during the extreme cold events this Standard seeks to address. For example, and without endorsing the specific parameters used or the resulting proposed requirements, Invenergy notes that the Public Utility Commission of Texas has an open docket (Project No. 53401, Electric Weather Preparedness Standards-Phase II) to set weather preparedness standards.  In that proceeding, the Commission Staff proposed (Memorandum and Proposal for Publication dated May 19, 2022), among other items, a standard of “…the lesser of the minimum ambient temperature at which the resource has experience sustained operations or the 95th percentile minimum average 72-hour temperature reported in ERCOT’s historical weather study…for the weather zone in which the resource is located.” (Emphasis added.)  The use of a multi-day average temperature with a percentile rather than the single coldest hour better targets the events the Standard is intended to address. The specific parameters (how many hours or days, which percentile, which zones, and other criteria) could be developed as part of the SDT’s process.  

(3) Invenergy recommends striking “continuous” from R1.1. to be more inclusive of all generation types, such as wind and solar generation output, which is variable, not continuous. 

(4) Invenergy suggests the following modifications to R1.4 to clarify Generation Owners declaring a commercial, technical, or operational constraint are not required to develop and implement a Corrective Action Plan:  

1.4. For each existing generating unit that requires either new freeze protection measures or modification of existing freeze protection measures to meet the requirements of 1.1, 1.2, or 1.3, the Generator Owner shall do one of the following:  

1.4.1. Develop and implement a Corrective Action Plan (CAP) that includes the following at a minimum:  

1.4.1.1. An identification of corrective action(s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s); 

1.4.1.2. A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;  

1.4.1.3. An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; OR  

1.4.2. Submit a declaration that the implementation or modification of freeze protection measures for existing generating unit(s) as required by Requirement R1 is not possible due to technical, commercial, or operational constraints as defined by the Generator Owner, and that no further corrective actions will be taken. The Generator Owner shall document technical, commercial, or operational constraints as defined by the Generator Owner as support for such declaration. 

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

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Yes, we have concern and want to ensure GO requirements will align with the BA.  Using coldest data information since 1975 does have concern, as the GO still won’t be able to document all applicable temp/wind/moisture/etc. facts that impact reality.  The requirement should only specify the minimum hourly temperature at the nearest National Weather Service location that plant has successfully operated. 

Existing generating units should only be required to analyze their designed operation parameters using freeze data and any cold weather limitations based on historic operations dating back to 1975, with defined interval(s) of operation. 

 

Robert Stevens, CPS Energy, 5, 6/17/2022

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We have a number of concerns related to clarity and consistency both within R1, and between R1 and other draft requirements.  

“Designed and maintained to be capable of continuous operations”
Our most significant concern is the proposed language in R1.1: “Each generating unit shall be designed and maintained to be capable of continuous operations….”  This language is significantly more specific, as well as narrower, than Recommendation 1f, and could result in a GO being found noncompliant with R1 based on an R6 Forced Outage, on the theory that if a unit is “designed and maintained to be capable of continuous operation” at the minimum hourly temperature, then a Forced Outage meeting the criteria of R6 should be impossible.  We do not believe that to be the SDT’s (or FERC’s) intent; R1.1-R1.3 should require GOs to implement freeze protection measures that they reasonably believe will be adequate, which they will supplement and improve pursuant to R6 and R1.4 if an event reveals a shortcoming.  We suggest that R1.1 be revised as follows, which parallels the wording of R1.2 and R1.3 but uses the words “based on” to reflect the common understanding of “design basis”: “The generating unit design shall be based on the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.”  If the SDT does not accept this proposed revision, it should at minimum (1) insert language clarifying that experiencing an R6 event is not evidence that a GO is in violation of R1, and (2) delete the words “and maintain” from R1.1, because maintenance of freeze protection measures is already required by R3.3.

Exceptions from R1.1-R1.3
We believe that the SDT intends that if an existing generator is developing and implementing a CAP pursuant to R1.4, or if an existing or new generator has determined (pursuant to R1.4.4 or R2, respectively) that technical, commercial, or operational constraints prevent it from meeting the criteria in R1.1-R1.3, then the GO will not be found noncompliant with R1.1-R1.3 on the basis of the issue(s) that are being addressed through the CAP or that are prevented by the constraint.  But that intention is not expressed in the standard: R1 mandates “freeze protection measures based on” R1.1, R1.2, R1.3, and R1.4 as “minimum criteria,” in all circumstances.  And R1 does not even mention the possibility of new generators being unable to meet the criteria, as contemplated by R2.  As currently written, a generator availing itself of R1.4 or R2 would be in violation of R1.1-R1.3.  We have proposed language below clarifying that applicable generating units must meet the criteria in R1.1-R1.3 except to the extent that the GO is developing and implementing a CAP, or has documented technical, commercial, or operational constraints.  

New vs. existing generators; combining R2 with R1.4.4
If the standard is to distinguish between “new” and “existing” generators—which we do not believe is necessary—then those terms must be defined for the purpose of this standard.  In particular, the SDT would need to clarify two issues: (1) whether a generator’s status as “new” or “existing” is fixed permanently based on some set date tied to the effectiveness of the standard (e.g. all generators in service on the state the standard becomes effective are “existing,” and all that come online after that point are “new generators” throughout their lifespans), or whether the generator’s status is instead determined at the time the standard is being applied (e.g. a generator that discovers the need for additional freeze control measures the day before it is to come online is a “new” generator, and thus must comply with R1.1-R1.3 immediately unless, per R2, a “technical, commercial, or operational constraint” prevents it from doing so, while a generator that makes the same discovery the day after beginning operations is “existing” and must develop and implement a CAP pursuant to R1.4).  And (2) for a unit that is under development on the effective date of the standard (or other relevant date), or at the time it discovers the need for additional freeze control measures, at what point in the process of design, permitting, construction, and testing does a generator become “existing” rather than “new”?  

It seems that the key difference in the treatment of “new” and “existing” generators in the draft standard is that “existing” generators develop a CAP if their freeze protection measures do not meet the criteria in R1.1-R1.3, and implement the CAP unless prevented by a technical commercial, or operational constraint, while “new” generators must meet the criteria in R1.1-R1.3 unless prevented by a constraint—in short, “new” generators skip the CAP step.  This is not, in our view, a distinction that requires the definition of separate classes of generators.  A simpler approach would be to revise R1 and merge it with R2 to provide three options for compliance for all generators: (1) if possible, have freeze control measures consistent with R1.1-R1.3; (2) if a generator’s freeze control measures are not consistent with R1.1-R1.3, but it is feasible to supplement or modify them to make them consistent, develop and implement a CAP to do so; and (3) if freeze control measures consistent with R1.1-R1.3 are not feasible due to a technical, commercial, or operational constraints, document the constraint and review every five years.  Please note that our proposed R1.5 below is based on the text of R2 and R2.1, not R1.4.4; as noted in response to Question 5 below, we suggest that R2.2’s five-year review requirement be moved to R4, and thus have not included that subrequirement in our proposed redline of R1.

Lack of deadline in R1.4
Requirement R1.4 requires GOs to develop CAPs in some situations, but provides no deadline by which they must do so.  The absence of a deadline places registered entities in the untenable position of having to guess, on a case-by-case basis, how long they have to develop a CAP before they would be deemed noncompliant.  The standard should also specify which events trigger the need to develop a CAP pursuant to R1.4, i.e. under which circumstances a generator could need new or modified freeze protection measures.  We believe that there are three situations with clear “trigger dates” in which a CAP could be required by R1.4: (1) implementation of this standard, where a generator’s existing freeze protection measures do not meet the new criteria; (2) an R6 event, and (3) discovery of the need for changes to freeze protection measures through some other means, including an R4 review that results in either an updated minimum hourly temperature necessitating changes to freeze protection measures, or removal of a previously-documented technical, commercial, or operational constraint.  (As explained below, we are suggesting that the CAP elements of R6 be moved to R1.4, leaving only the identification and analysis of the event in R6.)  We suggest that CAPs developed when this standard first becomes effective, and in response to an R6 event, use the same deadline as currently proposed in R6: “150 days subsequent to the [event/effective date of this Requirement] or by July 1 that follows the [event/effective date of this Requirement], whichever is earlier.”  CAPs developed in response to some other means of discovery of the need for changes, including R4 updates, should be developed by July 1 of the year following the calendar year in which the review or other means of discovery takes place.  This last class of CAPs should not use the same “by July 1 that follows the [completion of the review]” language as other CAPs, because doing so would force a GO that happened to complete a review or discover an issue in June to develop a CAP in less than a month.  And development of such CAPs should have only a date deadline, not an alternative number of days; otherwise, a GO conducting numerous R4 reviews in a calendar year would have an incentive to delay completion of any reviews it thinks likely to result in the need for a CAP, in order to avoid having to develop CAPs at the same time it is continuing its review of other units).

Overlap between R1, R4, and R6
R1, R4, and R6 contain overlapping requirements; for the sake of clarity, and to avoid duplicative noncompliance situations, these overlaps should be eliminated and the relationships between the requirements clarified.  
As currently drafted, R1 requires a CAP where a generator “requires either new freeze protection measures or modification of existing freeze protection measures.”  R4.3 requires each GO to “[r]eview whether its generating units have the freeze protection measures required to operate at the lowest temperature established pursuant to Requirement R1 and, if not, implement appropriate modifications per the requirements of Part 1.4.”  A GO that fails to “implement appropriate modifications per the requirements of Part 1.4” would thus be noncompliant with both R4.3 and R1.4.  This issue could be remedied with a minor edit to R4.3: replace “and if not, implement appropriate modifications per the requirements of R1.4” with “If freeze protection measures must be supplemented or modified as a result of the updated lowest temperature, the requirements of Part 1.4 apply.”  
There is a similar overlap between R1.4 and R6, although R6 does not mention R1.4.  R6 requires a GO that has experienced a qualifying event to develop a CAP meeting requirements essentially identical to those of R1.4, with the addition of two analysis requirements (“[a] summary of the identified cause(s) for the equipment freezing event where applicable and any relevant associated data” and “[a] review of applicability to similar equipment at other generating units owned by the Generator Owner”).  As drafted, an R6 event would trigger the requirements to develop a CAP pursuant to both R6 and R1.4, unless the R6 analysis identified no need for changes to freeze protection measures.  As with the overlap between R1.4 and R4, a failure to develop a CAP would result in an entity being noncompliant with two essentially identical requirements.  We suggest replacing R6.2.3 through R6.2.6 with a statement that “Corrective actions in response to an analysis required by R6, including new or modified freeze protection measures, are subject to the requirements of Part 1.4.”  Language should be added to R1.4 to indicate that it applies to the incorporation of lessons learned pursuant to R6; and the R6.2.3 requirement to identify corrective actions for “identified similar units” can be added to R1.4.1, e.g. “and, if applicable, any similar units identified pursuant to R6.2.2.”

Proposed language is attached in redline and clean format.

 

 

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

TAPS proposed language Q4.docx

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AE has the following concerns and suggestions:

  1. The R1 language may be interpreted as generators having to collect and monitor temperature data within their own premises, as opposed to being allowed to rely on documented temperature data within an identified third party monitored weathter station or recognized weather data source such as NOAA. AE would like to be able to rely on minimum temperature data as recorded from the closet National Weather Service Station (mainly Austin Bergstrom Airport Weather Station). The record minimum temperature data from such NOAA source since 1975 is only available at the daily level. Whether this daily minimum data correlates to hourly minimum temperatures is unknown. In addition, summer temperature data is not necessary and AE’s suggestion would be to only analyse temperature data for the winter months as defined by the BA. In addition, AE would recommend changing the language from hourly minimum temperature to annual minimum temperature in addition to making it clearer that the requirement doesn’t add the burden on entities to collect and monitor hourly temperatures at their own plant facilities and that entities are able to comply by utilizing available third party weather data at a nearby location.
  2. R1 and its sub-parts could be read to require continuous operation at the documented minimum hourly temperature, and that if a unit tripped at or above that minimum temperature during an extreme cold weather event, it could be deemed out of compliance.  AE believes the SDT’s intent is to require the implementation of freeze protection measures designed with the intent of continuous operation at the documented minimum hourly temperature.  R1 states the GO  shall ensure generating units implement freeze protection measures, and M1 states each GO will have dated evidence that demonstrates it has freeze protection measures.  However, M1 also says “in accordance with R1” and R1 part 1.1 says “Each generating unit shall be designed and maintained to be capable of continuous operations at the documented minimum ….”  AE requests that the SDT clarify the language to ensure the compliance expectation is not continuous operation.  No Generator Owner can guarantee its resource will continue to run even if it has implemented the required freeze protection measures.

Michael Dillard, Austin Energy, 5, 6/17/2022

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ACP generally supports R1, but notes this support is conditioned on the retention of the “commercial, technical, or operational constraints” pathway in 1.4.2 and 1.4.4, which constructively addresses a concern ACP raised in comments on the draft standard authorization request (SAR).  Without the commercial, technical, or operational constraints pathway, generators could be forced to retire if they do not have a feasible compliance path, which would exacerbate the challenge of generator availability during extreme cold weather. If the commercial, technical, or operational constraints pathway is removed, ACP would oppose R1.

ACP has one concern about this section as currently drafted:

1. In 1.1 the use of the phrase “continuous operations” in the following sentence is problematic for variable energy resources that are dependent on the wind or sun to generate: “Each generating unit shall be designed and maintained to be capable of continuous operations at the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.” (emphasis added)

Put simply, wind and solar generation output is variable, not continuous.  Therefore, as drafted, GOs of variable generation resources arguably cannot comply.  ACP recommends the following redline be adopted (remove the word "continuous" from the sentence):

Each generating unit shall be designed and maintained to be capable of operations at the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

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FMPA does not believe the proposed methodology is an appropriate way to address the the risk presented in recommendation 1f. At heart there are two key issues. First is that while we understand the technical rationale for selecting 1975 as a date to go back to, this is still quite arbitrary and not a very rigorous (statistically) way to ensure we have selected the appropriate level of risk protection. The second issue relates to the first with respect to duration of cold weather. When determining the design requirements for plant equipment to address cold, the temperature, and duration, are equally important. It takes time to freeze. A running plant will withstand most 1hr temperature dips. We do not believe it is appropriate to arbitrarily take the lowest 1 hr (which is really sub-1hr) temperature over the last 47 years and extrapolate that 1 hour duration to “continuous”.

To address both of these issues, a probabilistic-based method should be deployed, which fits the available temperature data to a standard probabilistic distribution and allows the level of extremity of both temperature and duration to be explicitly selected (for example saying the plant must be continuously operable for all temperatures and durations equal to or below “x” standard deviations from the mean). The currently proposed method will result in some areas where plants are weather hardened unnecessarily as well as other areas where the past 47 years of data did not include a temperature as low as, say, the one we get next year. Wind speed should likewise be considered probabilistically. All three of these items should be addressed as part of a methodology that is part of the GO’s cold weather preparedness plan(s). The current proposal implies that plants in south Florida will need to be fully enclosed in a building the way they build plants in North Dakota, because it fails to realize that while South Florida may have seen a brief freezing temperature in the last 47 years, the duration of that freeze is statistically so unlikely to last for 6 hours that modifying plants to address it would be ridiculous.

In addition, this requirement is silent on what data sources will be acceptable (1st order weather station, NOAA, etc) and what constitutes determination that “reliable” data is “not available”. What if no reliable data is available? These issues would need to be resolved when adopting a more rigorous probabilistic methodology.

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

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Summer Esquerre, NextEra Energy, 5, 6/17/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

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LPPC is concerned that the proposed language in EOP-012-1 R1, as well as Parts 3.1 and 4.1, places significant administrative and analytical burden on entities, and potentially complicates the assessment of design capabilities. LPPC is concerned that collecting and maintaining hourly temperature data would amount to finding a needle in a haystack (over 400,000 data points in a 50 year time period). Instead, LPPC recommends utilizing annual temperature data to identity the lowest temperature recorded for the year. This approach results in a smaller set of data to maintain and is easier for entities to identify the lowest temperature needed for freeze protection. Additionally, analyzing hourly data from summer periods is not beneficial, so a lowest recorded temperature for the year is more appropriate.

LPPC recommends modifying Part 1.1, Part 3.1, and Part 4.1 to remove the requirement for a specific interval, and only require documentation of the lowest recorded temperature since 1975, as follows. These changes allow an Entity to determine whether hourly, daily, or annual is the most appropriate interval for their assessments.

Recommended changes to Parts 1.1, 3.1, and 4.1:

Part 1.1: “Each generating unit shall be designed and maintained to be capable of continuous operations at the lowest recorded ambient temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.”

Part 3.1: “Lowest recorded ambient temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.”

Part 4.1: “Review the lowest recorded ambient temperature developed pursuant to Part 3.1, and update the cold weather preparedness plan with the lowest temperature as necessary.”

These comments have been endorsed by LPPC.

LPPC, Segment(s) 3, 1, 6/17/2022

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AZPS supports EEI’s comments, particularly regarding giving consideration to the financial impact of cold weather modifications vs. retiring a generating unit and that R1 should not specify that generating units must be redesigned to meet certain freeze protection requirements, along with the proposed revisions to R1.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

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Agree with the NAGF comments, but also want to have the SDT consider the following:

For some nuclear plants the temperature band is built into the design and/or licensing basis of the plant.  Changing the analysis is not cost effective nor prudent.  NERC required temperature bands in excess of what NRC requires for safety of the plant is prohibitive of economic, cost effective operation.  Recommend either a statistical approach be taken similar to the NRC to have more realistic numbers than lowest value seen since 1975 or that nuclear is exempt based on extensive design basis analysis that is already done. 

One example of an existing nuclear power plant (NPP):

The Updated Safety Analysis Report (USAR) for the NRC states that the NPP is designed for a low temperature of -5F dry bulb which will only be exceeded 1% of the time during the winter.  If -5F is exceed a condition report is generated to allow tracking of amount of time the temperature is exceeded.   Per the 1972 ASHRAE Handbook of Fundamentals the winter is considered to be December, January, and February for a total of 2160 hrs each year.   The design of -5 was taken from the same 1972 ASHRAE Handbook for the location of the NPP which substantiates the statement in the USAR that the design maximum and minimum temperatures will be exceeded approximately 1% of the time during a normal winter.  To verify the NPP maintains within this statement a cumulative percentage has been determined for winter months for the period of July 2004 to March 21, 2022.  These results show the design low temperature is exceeded only .49% of the time during the winter.

Based on the extensive design analysis performed at the NPP and ongoing trending that occurs each winter to ensure we are bounded by the analysis, it doesn’t seem practical to change the entire design/licensing basis of the plant to match the minimum hourly temperature experienced since 1/1/1975

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

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EOP-012-1 is unclear and confusing because of disorganized language and grammatical errors. For example, generating units do not implement anything. Many pieces of equipment do not “freeze,” i.e., solid metal is already “frozen” by definition. Rather, equipment fails due to improper protection from extreme cold. The requirements should be stated so that the registered entity, e.g., the Generator Owner, is the one implementing the action. Distinct obligations should be contained in separate requirements, not combined at the requirement part and sub-part levels. 

 

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

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The Federal Power Act Section 215 definition of “Reliability Standard” states in relevant part that the term includes requirements for “the design of planned additions or modifications to such facilities to the extent necessary to provide for reliable operation of the bulk power system….”  This phrase suggests that reliability standards cannot have requirements that require unplanned modifications to facilities.  EEI asks the standard drafting team to request the NERC legal department to provide a legal memorandum on whether Section 215 of the Federal Power Act allows a Reliability Standard to require existing generating units to be redesigned or otherwise modified to meet certain freeze protection requirements beyond their original design as set forth in Requirement R1.

 

Additionally, consideration should be given to the financial impact of the cold weather modifications to existing generating resource owners (GOs) who must balance the benefits of modifying a resource versus retiring it.  For this reason and for the overall reliability of the BES, language for Requirement R1, part 1.4.4 should state that the GO is the authority to make such determinations to prevent early retirement of resources which could result in increased pressures on resource adequacy and BES reliability.   

 

EEI does not agree that R1 should specify that generating units must be redesigned to meet certain freeze protection requirements.  Instead R1 should require generating units to have the ability to continuously operate within the specified operating ranges.  How this is accomplished should be up to the owner. 

 

The wind and precipitation requirements contained in Requirement R1, subparts 1.2 and 1.3 should be combined into subpart 1.1. because as currently written an entity could be faced with multiple violations as a result of their non-compliance for a wind and precipitation violation while any mitigation to address these two issues would be the same. 

To address the above issues, we recommend the following revisions to Requirements R1:

R1. Each Generator Owner shall ensure generating units implement freeze protection measures based on the following minimum criteria: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

 

1.1  Each generating unit shall be capable of continuous operations at the documented minimum hourly temperature experienced at its location since 1/1/1975, or a lesser period if reliable data is not available to 1975, and address the cooling effects of wind and precipitation (e.g., sleet, snow, ice and freezing rain).

1.2  For each generating units that do not meet part 1.1 above, the Generator Owner shall develop and implement a Corrective Action Plan (CAP) which includes the following at a minimum:

1.2.1        An identification of corrective action (s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

1.2.2        A timetable for implementing the corrective action(s) from Part 1.2.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;

1.2.3        An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

1.2.4        In the event a GO is unable to fully mitigate their generating unit to have the continuous operating capability as defined under R1, a determination shall be made, where deemed appropriate by the Generator Owner based on their review of Parts 1.2.1 through 1.2.3, that no additional revisions to the cold weather preparedness plan(s) will be made and that no further corrective actions will be taken. The Generator Owner shall document the technical, commercial, or operational constraints as defined by the Generator owner as support for such determination

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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No Comment.

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Colorado Springs Utilities agrees with comments endorsed by LPPC

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

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The proposal to require the implementation of new or modified freeze protection measures, as currently drafted, is not sufficiently defined or limited in scope and would propose unreasonable and costly compliance burdens on Generator Owners.

First, the standard should better define "temperature" as used in R1.1--e.g., dry bulb/ambient, wet bulb, dew point, etc.--as well as specify the location at which temperature is to be measured--e.g., plant site versus nearest weather station. Luminant does not have a particular preference on the definition, so long as it is clear what is meant by "temperature."  

Second, a more reasonable duration requirement should be set than the proposed single lowest hourly temperature ever recorded since January 1, 1975. The proposed single hour standard does not adequately account for nuances in how resources are impacted by temperature and thus is overly rigid, without a clear reliability benefit. For example, a particular resource may not be impacted by a few minutes or even an hour at a given low temperature, but may face operational issues at a slightly higher temperature for prolonged periods of time (e.g., two or three days of extended low temperatures). For purposes of reliability, extended periods of cold, rather than a few minutes or even an hour at an extreme low temperature, are more concerning and are the circumstances for which Generator Owners should be reasonably prepared. In addition, the proposed single hour standard would impose an unreasonably burdensome, costly, and impractical standard on Generator Owners that is unlikely to produce benefits commensurate with the likely compliance costs. Such costs would be significant, given that retrofitting of units would likely be required to "ensure" (which is not even possible) continuous operation of a resource at the coldest temperature ever to occur for one hour in the past nearly 50 years. Such costs would be especially problematic in a region like ERCOT, where competitive generators have no mechanism for cost recovery (unlike in fully regulated utility regimes). Further, even in ISOs with capacity markets, significant winterization costs could cause a unit to not clear the capacity auction, thus potentially resulting in stranded costs. Significant compliance costs related to weather preparedness and freeze protection could force a resource into early retirement.

In contrast, a requirement to reasonably prepare to operate continuously in the face of prolonged, but more likely cold temperatures is more practical and more likely to improve overall reliability of the grid. One option as an alternative to the proposed lowest hourly standard would be to use a percentile standard, such as the one proposed by the Public Utility Commission of Texas (PUCT) in a pending rulemaking proceeding (currently in the comment phase of the rulemaking process). That rule includes a proposal that generators and transmission operators implement weather emergency preparedness measures that are reasonably expected to ensure sustained operation of the resource at the 95th percentile minimum average 72-hour temperature as reported in a historical weather study published by the Balancing Authority (ERCOT) for the weather zone in which the resource operates. The use of a conservative percentile (95th percentile) and a longer duration (72 hours) better captures likely future cold weather outcomes, rather than focusing on the lowest hourly temperature ever recorded in the past nearly 50 years, which does not represent a likely future temperature or one that would likely be experienced in a future winter for any appreciable amount of time. Further, a 95th percentile/72-hour standard, coupled with the qualification that the requirement is one of reasonable preparedness, is one that Generator Owners could more feasibly meet, at a more reasonable compliance cost, than the SDT's proposed lowest hourly temperature standard.

Alternatively, R1 could be written to conform more closely to the preparedness requirements in R3.4.2, which reference the generating unit's minimum design temperature, historical operating temperature, or current cold weather performance temperature determined by an engineering analysis. Those standards recognize the practicality of the design and performance of a particular resource, rather than imposing an impractical standard based on the coldest temperature recorded since January 1, 1975 (which may significantly pre-date the commercial operation date for a given resource).

Either way, the requirement to implement freeze protection measures or preparedness measures to operate to an exact coldest hourly temperature (with "temperature" undefined) dating back to January 1, 1975 is unduly burdensome, impractical, and unreasonable and should not be adopted.

Finally, in R1.4.2, the timetable for corrective action plans should be revised to provide for the development of a plan in five years, rather than specify a timetable for implementation.       

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

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Entergy requests clarity around expectation from R1.3. 

Entergy, Segment(s) 1, 5, 12/13/2017

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Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

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To retrofit existing units to a historical low temperture below the design temperature should be accompanied with clear cut requirements for an entity to regain the necessary expense for each unit. An IPP does not have the resources vertically integrated utilities have to recoup the required costs or to even front the costs until recovery can be realized.   The commercial component of these activities must occur concurrent with the reliability aspects;  Heretofore, only the reliability aspects have been identified.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

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EOP-012-1 R1 should be modified to allow for an Engineering Analysis to see if units are subjected to potential freezing, with the possibility of eliminating all requirements of the Standard.  Temperature alone is not a true indication of freezing, a time component is also necessary to understand the heat losses.  Setting design requirements based on the lowest hourly temperature data places an unecessary burden on southwestern desert facilities that return to above freezing temperatures in a matter of hours.  In reviewing the five lowest recorded temperatures since 1975 for IID units, the temperature always returned above freezing the same day.  It did not last multiple days or weeks, as in the ERCOT region.   

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

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R1.4.2 establishes a timetable for implementing corrective freeze protection measures actions but the proposed Standard does not establish a implementation period/deadline for the the corrective actions.  Recommend that R1.4.2 language be modified to require a reasonable time period/deadline for implementing corrective freeze protection measures.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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I agree with TAPs comments, pasted below:

We have a number of concerns related to clarity and consistency both within R1, and between R1 and other draft requirements. 

“Designed and maintained to be capable of continuous operations”

Our most significant concern is the proposed language in R1.1: “Each generating unit shall be designed and maintained to be capable of continuous operations….”  This language is significantly more specific, as well as narrower, than Recommendation 1f, and could result in a GO being found noncompliant with R1 based on an R6 Forced Outage, on the theory that if a unit is “designed and maintained to be capable of continuous operation” at the minimum hourly temperature, then a Forced Outage meeting the criteria of R6 should be impossible.  We do not believe that to be the SDT’s (or FERC’s) intent; R1.1-R1.3 should require GOs to implement freeze protection measures that they reasonably believe will be adequate, which they will supplement and improve pursuant to R6 and R1.4 if an event reveals a shortcoming.  We suggest that R1.1 be revised as follows, which parallels the wording of R1.2 and R1.3 but uses the words “based on” to reflect the common understanding of “design basis”: “The generating unit design shall be based on the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975.”  If the SDT does not accept this proposed revision, it should at minimum (1) insert language clarifying that experiencing an R6 event is not evidence that a GO is in violation of R1, and (2) delete the words “and maintain” from R1.1, because maintenance of freeze protection measures is already required by R3.3.

Exceptions from R1.1-R1.3

We believe that the SDT intends that if an existing generator is developing and implementing a CAP pursuant to R1.4, or if an existing or new generator has determined (pursuant to R1.4.4 or R2, respectively) that technical, commercial, or operational constraints prevent it from meeting the criteria in R1.1-R1.3, then the GO will not be found noncompliant with R1.1-R1.3 on the basis of the issue(s) that are being addressed through the CAP or that are prevented by the constraint.  But that intention is not expressed in the standard: R1 mandates “freeze protection measures based on” R1.1, R1.2, R1.3, and R1.4 as “minimum criteria,” in all circumstances.  And R1 does not even mention the possibility of new generators being unable to meet the criteria, as contemplated by R2.  As currently written, a generator availing itself of R1.4 or R2 would be in violation of R1.1-R1.3.  We have proposed language below clarifying that applicable generating units must meet the criteria in R1.1-R1.3 except to the extent that the GO is developing and implementing a CAP, or has documented technical, commercial, or operational constraints. 

New vs. existing generators; combining R2 with R1.4.4

If the standard is to distinguish between “new” and “existing” generators—which we do not believe is necessary—then those terms must be defined for the purpose of this standard.  In particular, the SDT would need to clarify two issues: (1) whether a generator’s status as “new” or “existing” is fixed permanently based on some set date tied to the effectiveness of the standard (e.g. all generators in service on the state the standard becomes effective are “existing,” and all that come online after that point are “new generators” throughout their lifespans), or whether the generator’s status is instead determined at the time the standard is being applied (e.g. a generator that discovers the need for additional freeze control measures the day before it is to come online is a “new” generator, and thus must comply with R1.1-R1.3 immediately unless, per R2, a “technical, commercial, or operational constraint” prevents it from doing so, while a generator that makes the same discovery the day after beginning operations is “existing” and must develop and implement a CAP pursuant to R1.4).  And (2) for a unit that is under development on the effective date of the standard (or other relevant date), or at the time it discovers the need for additional freeze control measures, at what point in the process of design, permitting, construction, and testing does a generator become “existing” rather than “new”? 

It seems that the key difference in the treatment of “new” and “existing” generators in the draft standard is that “existing” generators develop a CAP if their freeze protection measures do not meet the criteria in R1.1-R1.3, and implement the CAP unless prevented by a technical commercial, or operational constraint, while “new” generators must meet the criteria in R1.1-R1.3 unless prevented by a constraint—in short, “new” generators skip the CAP step.  This is not, in our view, a distinction that requires the definition of separate classes of generators.  A simpler approach would be to revise R1 and merge it with R2 to provide three options for compliance for all generators: (1) if possible, have freeze control measures consistent with R1.1-R1.3; (2) if a generator’s freeze control measures are not consistent with R1.1-R1.3, but it is feasible to supplement or modify them to make them consistent, develop and implement a CAP to do so; and (3) if freeze control measures consistent with R1.1-R1.3 are not feasible due to a technical, commercial, or operational constraints, document the constraint and review every five years.  Please note that our proposed R1.5 below is based on the text of R2 and R2.1, not R1.4.4; as noted in response to Question 5 below, we suggest that R2.2’s five-year review requirement be moved to R4, and thus have not included that subrequirement in our proposed redline of R1.

Lack of deadline in R1.4

Requirement R1.4 requires GOs to develop CAPs in some situations, but provides no deadline by which they must do so.  The absence of a deadline places registered entities in the untenable position of having to guess, on a case-by-case basis, how long they have to develop a CAP before they would be deemed noncompliant.  The standard should also specify which events trigger the need to develop a CAP pursuant to R1.4, i.e. under which circumstances a generator could need new or modified freeze protection measures.  We believe that there are three situations with clear “trigger dates” in which a CAP could be required by R1.4: (1) implementation of this standard, where a generator’s existing freeze protection measures do not meet the new criteria; (2) an R6 event, and (3) discovery of the need for changes to freeze protection measures through some other means, including an R4 review that results in either an updated minimum hourly temperature necessitating changes to freeze protection measures, or removal of a previously-documented technical, commercial, or operational constraint.  (As explained below, we are suggesting that the CAP elements of R6 be moved to R1.4, leaving only the identification and analysis of the event in R6.)  We suggest that CAPs developed when this standard first becomes effective, and in response to an R6 event, use the same deadline as currently proposed in R6: “150 days subsequent to the [event/effective date of this Requirement] or by July 1 that follows the [event/effective date of this Requirement], whichever is earlier.”  CAPs developed in response to some other means of discovery of the need for changes, including R4 updates, should be developed by July 1 of the year following the calendar year in which the review or other means of discovery takes place.  This last class of CAPs should not use the same “by July 1 that follows the [completion of the review]” language as other CAPs, because doing so would force a GO that happened to complete a review or discover an issue in June to develop a CAP in less than a month.  And development of such CAPs should have only a date deadline, not an alternative number of days; otherwise, a GO conducting numerous R4 reviews in a calendar year would have an incentive to delay completion of any reviews it thinks likely to result in the need for a CAP, in order to avoid having to develop CAPs at the same time it is continuing its review of other units).

Overlap between R1, R4, and R6

R1, R4, and R6 contain overlapping requirements; for the sake of clarity, and to avoid duplicative noncompliance situations, these overlaps should be eliminated and the relationships between the requirements clarified. 

As currently drafted, R1 requires a CAP where a generator “requires either new freeze protection measures or modification of existing freeze protection measures.”  R4.3 requires each GO to “[r]eview whether its generating units have the freeze protection measures required to operate at the lowest temperature established pursuant to Requirement R1 and, if not, implement appropriate modifications per the requirements of Part 1.4.”  A GO that fails to “implement appropriate modifications per the requirements of Part 1.4” would thus be noncompliant with both R4.3 and R1.4.  This issue could be remedied with a minor edit to R4.3: replace “and if not, implement appropriate modifications per the requirements of R1.4” with “If freeze protection measures must be supplemented or modified as a result of the updated lowest temperature, the requirements of Part 1.4 apply.” 

There is a similar overlap between R1.4 and R6, although R6 does not mention R1.4.  R6 requires a GO that has experienced a qualifying event to develop a CAP meeting requirements essentially identical to those of R1.4, with the addition of two analysis requirements (“[a] summary of the identified cause(s) for the equipment freezing event where applicable and any relevant associated data” and “[a] review of applicability to similar equipment at other generating units owned by the Generator Owner”).  As drafted, an R6 event would trigger the requirements to develop a CAP pursuant to both R6 and R1.4, unless the R6 analysis identified no need for changes to freeze protection measures.  As with the overlap between R1.4 and R4, a failure to develop a CAP would result in an entity being noncompliant with two essentially identical requirements.  We suggest replacing R6.2.3 through R6.2.6 with a statement that “Corrective actions in response to an analysis required by R6, including new or modified freeze protection measures, are subject to the requirements of Part 1.4.”  Language should be added to R1.4 to indicate that it applies to the incorporation of lessons learned pursuant to R6; and the R6.2.3 requirement to identify corrective actions for “identified similar units” can be added to R1.4.1, e.g. “and, if applicable, any similar units identified pursuant to R6.2.2.”

Proposed language for R1

Proposed language (clean)

R1.       Each Generator Owner shall implement freeze protection measures for each applicable generating unit based on the minimum criteria set forth in R1.1 through R1.3, except to the extent that (i) it is developing and implementing a Corrective Action Plan (CAP) pursuant to R1.4 to enable a unit to meet the criteria set forth in R1.1 through R1.3, or (ii) it has determined, pursuant to R1.5, it is not able to implement freeze protection measures consistent with R1.1 through R1.3 or a CAP developed pursuant to R1.4 due to technical, commercial, or operational constraints:  [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

1.1.     The generating unit design shall be based on the documented minimum hourly temperature experienced at its location since 1/1/1975 or a lesser period if reliable data is not available to 1975;

1.2.     The generating unit design shall account for the cooling effect of wind; and

1.3.     {C}The generating unit design shall account for the impacts on operations due to precipitation (e.g., sleet, snow, ice, and freezing rain); or

1.4.     {C}For each generating unit whose freeze protection measures require supplementation and/or modification in order to meet the criteria in R1.1 through R1.3, or based on lessons learned pursuant to R6, the Generator Owner shall develop a Corrective Action Plan (CAP) by the deadline determined pursuant to R1.4.2. 

1.4.1.      The CAP shall include the following at a minimum:

1.4.1.1.            An identification of corrective action(s) for the affected unit(s) (and, if applicable, any similar units identified pursuant to R6.1.2), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

1.4.1.2.            A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner; and

1.4.1.3.            An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

1.4.2.      The Generator Owner shall develop the CAP according to the applicable deadline from the following:

1.4.2.1.            A Generator Owner that determines prior to the effective date of this Requirement that its existing freeze protection measures do not meet the criteria set out in R1.1 through R1.3 shall develop a CAP by no later than 150 days following the effective date of this Requirement, or the July 1 that follows the effective date of this Requirement, whichever is earlier.

1.4.2.2.            A Generator Owner that has experienced an event meeting the criteria in R6 shall develop a CAP by no later than 150 days subsequent to the event or by July 1 that follows the event, whichever is earlier. 

1.4.2.3.            A Generator Owner that has determined in circumstances other than those described in R1.4.2.1 and R1.4.2.2 that its freeze protection measures require supplementation or modification, including but not necessarily limited to in response to an updated minimum hourly temperature pursuant to Requirement R4.3 or the removal of a technical, commercial, or operational constraint based on a review pursuant to Requirement R4.4, shall develop a CAP by no later than July 1 of the calendar year following the calendar year in which the Requirement R4 review was conducted or the need for the supplementation or modification was otherwise discovered, as applicable.

1.4.3.      The Generator Owner shall implement the CAP according to the timetable established pursuant to R1.4.1.2, except to the extent that it is unable to implement the CAP due to a technical, commercial, or operational constraint documented per R1.5.

1.5.     Each Generator Owner that is not able to implement (i) freeze protection measures consistent with R1.1 through R1.3 or (ii) a CAP developed pursuant to R1.4 for a generating unit(s) due to technical, commercial, or operational constraints as defined by the Generator Owner shall document its determination and the constraints on implementation.

Alternative Suggestions

Alternative Revisions to R1.4

If the SDT retains R1.4.4 as a subrequirement under R1.4, it should revise R1.4 to state that the CAP must include “the following at a minimum R1.4.1-R1.4.3.”  R1.4.4 is required only where a GO cannot implement identified corrective actions; it is not a minimum requirement of every CAP.

Alternative Revisions to R1.4.4

If the SDT does not consolidate R2 with R1.4.4 as suggested above, or if it retains the language of R1.4.4 rather than that of R2, it should at minimum eliminate unnecessary inconsistencies between the two requirements, and should delete from R1.4.4 (and from R6.2.6, if that separate subrequirement is retained) the words “that no revisions to the cold weather preparedness plan(s) are required,” which are unnecessary and give the erroneous impression that R1.4.4 applies to situations where no changes are needed, as opposed to where changes cannot be made due to constraints.  Our suggested revisions to the language of R1.4.4, to the extent that language is retained:

Where deemed appropriate by the Generator Owner, documentation that the Generator Owner is not able to implement some or all of the corrective actions identified pursuant to Parts 1.4.1-1.4.3 due to technical, commercial, or operational constraints as defined by the Generator Owner.

Alternative elimination of duplication between R6 and R1.4

Finally, as also noted in response to Question 10 below, if the SDT retains a separate CAP requirement in R6, it must clarify in R1.4 that corrective actions in response to an R6 event are subject only to R6, not R1.4.  Proposed language:

For each generating unit whose freeze protection measures require supplementation and/or modification in order to meet the criteria in R1.1 through R1.3 (except when such supplementation or modification of freeze protection measures is undertaken in response to an R6 event, in which case the CAP requirements of R6 apply)…

 

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

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Michael Jones, National Grid USA, 1, 6/17/2022

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Xcel Energy has significant concerns with the language in the draft EOP-012 R1 and supports the comments of EEI.

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

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TMLP echoes the comments submitted by the Rebecca Baldwin on behalf of TAPS Group for Question 4. 

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

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First of all upgrading freeze protection design will take several years or more for each unit not currently meeting the Standard.  This time period will have to include budgeting for the cost, evaluation by design engineers who may not be available during the implementation period, supply chain issues with everyone in the country buying heat trace hardware and insulating material all at the same time.  The second concern is that the cost per Facility could exceed several million dollars.  More for large coal units.  Third, the design temperature, wind speed and precipitation criteria can’t be functionally tested until the weather meets the parameters specified by the design and stays there for an extended period.  Untested it could be argued that the unit was in violation of R1 if it has issues at the specified design parameters.  Upgrading the design of a Facility to operate continuously at a temperature that may have been reached only one time in fifty years is not acting as a good steward with the money our customers pay for reliable electricity service.  We recommend that the implementation plan allow 10 years for compliance with R1.

Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

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JEA believes that continuous operations at a single recorded temperature will be a significant undertaking (cost, manpower, active maintenance & associated risks) without much benefit in Jacksonville, FL. Our lowest temperature was in 1985 at 7 degrees F for two hours, but our mean low for December, January, and February is 28, 25, and 28 degrees F. To operate for 7 degrees F continually even during the winter season will place a strain on resources, requiring heat tape where insulation would be sufficient (based upon a conservative forecast).

Some exclusion for regions that experience minimal freezes should be considered. For example, “If hourly temperature data shows that the entity experienced less than 10 five-hour freezes in the past five years, continuous operation at the minimum temperature is not required.” This is a suggestion, but a suitable expert could be consulted to suggest a time element (X-hour freezes) with a suitable number of cases (Y instances) over a recent time period (past Z years).

Joe McClung, JEA, 1, 6/17/2022

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PNM supports EOP-012-1 R1 as long as the language in R1.1 concerning if reliable data is not available back to 1975 an acceptable lesser period is allowed.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

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Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

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Minnesota Power does not believe that freeze protection measures need to be adjusted for its units based on its reliability in past extreme temperatures, however Minnesota Power believes that having an engineering design rated for a 50-year minimum hourly temperature is not feasible, could be extraordinarily costly, and would not improve reliability.  It would be difficult to impossible to find an engineer willing to guarantee that these units could operate in -59 Fahrenheit degree temperatures for extended periods of time.  Minnesota Power also agrees with NSRF comments recommending to implement a statistical approach similar to NERC to have a more realistic method than identifying the lowest value seen since 1975.

Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

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Capital Power supports the NAGF comments / concerns / suggested revisions in relation to this question. 

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

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As an initial matter, we are concerned that the phrase “technical, commercial, or operational constraints” is not sufficiently specific and cannot be interpreted precisely enough to yield incremental reliability benefits.  As a generator owner, our view is that all cold weather technical and operational constraints distill down to economic choices.  Few, if any, generators are incapable of meeting the proposed standard for technological or operational reasons.  The level of investment may vary by technology, and in some cases be significant, but technical and operational constraints can be overcome.   Given the significant investment required to ensure a resource can meet the proposed Standards, we would expect a significant number of generators to self-determine that they are exempt from meeting the Standards.  As currently worded, compliance with the Standards appear optional.  Fundamentally, a Reliability Standard that is supposed to enhance reliability and can be met in almost all cases through investment should not be discriminatory - e.g. old or new resource, class of resource,  or optional.    This vaguely defined exclusion does not appear to meet this standard.   The exemption will also create a patchwork of varying degrees of reliability from generator-to-generator that will make it more difficult for the BAs to manage their grids in extreme conditions.   

 

Additionally, the language in §1.4.2 as drafted is unclear as to whether existing generators that have “technical, commercial, or operational constraints” are exempted from the strict requirement of complying with the standard.  Specifically, it is unclear whether the “constraints” determination applies to the “timetable” or whether the determination applies to the absolute performance requirement.  This language is contrasted with R2 that applies to new generators and is unequivocal in its meaning:

 

“Each Generator Owner that is not able to implement freeze protection measures for new generating unit(s) as required by Requirement R1 due to technical, commercial, or operational constraints as defined by the Generator Owner shall”  (emphasis added)

 

Finally, we think the perceived need for the new generator exemptions belies the overly onerous standard and may be intended for the benefit of a specific resource class.  The fact that the drafting team is contemplating an exemption for new generators should provide NERC and stakeholders pause on the reasonableness of the proposed Standards and what exactly the new generator exemption is intending to address. 

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

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For some Canadian entities, units already operate in cold weather annually from November to March. These requirements represent an added administrative burden.

 

The new reliability standards requirement should be part of a regional variance for the regions where winterization programs are not in place. Canadian entity generators already operate successfully in cold climates with extreme conditions. For such entities, this is an additional compliance burden, with no additional benefit to grid reliability

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

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NAGF Comments: The NAGF has several concerns related to the requirement.

a. First, the process being used is ignoring, and appears to conflict with, NERC’s stated Market Principles. This requirement will most likely cause a depression of prices for energy provided while increasing the cost to own and operate generation. Together, this structure will drive investment out of the generation market at a time when multiple areas of the NERC footprint are seeing concerns with the ability for operators to meet expected load during normal and extreme weather. These issues are why NERC needs to address the conflict between the Market Principle which states “Standards shall not define an adequate amount of, or require expansion of, bulk power system resources or delivery capability.” and the proposed requirement. By requiring generators to improve their capability to withstand extreme weather beyond the generator’s current design, they are requiring expansion of the delivery capability. This is the same as requiring Transmission Owners or Distribution Providers to harden their wires so no customers will lose power due to a hurricane or tornado. This requirement also appears to conflict with NERC’s Market Principle “A reliability standard shall not give any market participant an unfair competitive advantage.” As long as some market participants are able to pass the costs associated with retrofitting units through to rate payers and other market participants are not able to pass the costs through to the end users, the proposal to require retrofits will provide some market participants advantages over other market participants in that market.

The NAGF does support the desire to allow the Transmission Planners, Balancing Authorities, Transmission Operators and Reliability Coordinators to better predict the point where extreme weather may cause problems but this requirement does not do that. Instead, this requirement puts the onus on generators to be able to operate through any cold weather event, regardless of the existing capability or limits including potentially more restrictive limits on Transmission, Distribution and fuel delivery.

While the NAGF grants that there are exclusions for the Generator Owner to take, these very exclusions cause the requirement to be completely unenforceable. As written, generator investments to improve or maintain generation may be determined to be too costly by the Generator Owner and therefore no effort need be made beyond writing down that the cost is too much for the benefit expected. With the allowed exceptions, it is even more critical that the BAs, TOPs, TPs and RCs understand each generator’s capability and use that data in their planning processes.

b.     NERC is moving forward with this requirement to retrofit existing generation without any effort to address Recommendation 2 in the report. If these two recommendations are not addressed together, it is extremely likely that Recommendation 2 will not be addressed until such time as investment in generation has suffered a great deal. Since reports, such as MISO’s Summer Readiness, are currently showing a significant potential for insufficient generation in the near future, further retirements and reduced investment in new generation could mean serving loads during most periods of the year will be tight if not impossible. As an example, when concerns already exist related to the retirement of generation causing problems for reliable service, NERC is proposing a requirement to raise the cost of continuous operation with no certainty related to the ability to recoup the costs. In fact, economic theory says that this type of requirement will depress market prices for energy during the winter, making even more generators uneconomic. This requirement will raise the cost to continue to operate the existing fleet of traditional generation, which pushes them to retire even faster.

c.      While the requirement mentions both the cooling effect of wind and precipitation, the language does not require any specific identification of impacts to the dry bulb temperature for operational purposes due to wind or precipitation. To the extent a Balancing Authority or Transmission Planner is using a dry bulb temperature to determine if a generator is able to maintain service, then failures to accurately and appropriately forecast seasonal capability will continue to occur. The classic example in this respect is the Polar Vortex of 2014, which caused no trouble in the PJM area (at Allentown, Pa) for a brief (1 hour) dip to of -4.0 F with a wind of 4.6 mph (-14.6 F wind chill) on 1/4/2014, but knocked units offline on 1/7/2014 at sustained conditions reaching 0 F with a 21.9 mph wind (-22.8 F wind chill).  How could these units be unreliable at 0 F when they proved themselves able to tolerate -4 F just three days earlier?  The answer is that the dry bulb temperature is the wrong parameter, and will always yield wrong expectations, regardless of EOP-012. If a unit is heat-traced for 0 F and a 10 mph wind (-16 F wind chill), for example, is it EOP-012 rated for 0 F, -16 F, or (if the max winter storm wind speed is 30 mph) 7 F (7 F and 30 mph yield a wind chill of -16 F)?  The first two alternatives fail to predict outages that will be suffered under blizzard conditions, while the last one is unreasonably pessimistic if applied as a general rule and not solely when a severe windstorm is expected.

d.     This requirement also makes no mention of a start-up capability, yet the report authors clearly state that failure to start was an issue. With most generators, a minimum operating temperature is very likely to have no bearing on whether a unit can start at that temperature. A unit’s ability to operate at a temperature is not the same thing as a unit’s ability to start. Until Balancing Authorities, Transmission Planners, and Transmission Operators utilize the correct information to formulate their plans, they will continue to fail to be adequately prepared. By failing to address startup capability in the standard until a Corrective Action Plan is required (which can be completed by stating that the conditions identified are for continuous operation and not related to startups), the standard is failing to address the critical issue: giving the Balancing Authority and other entities important information about the generator that should be used to appropriately plan system operations.

e.     Requirement 1 mentions the cooling effects of wind and precipitation. However, Requirements 3 and 4 and 6 look only at temperature and ignore wind and moisture completely. Each of these requirements must be consistent.

f.       Generator Owners are being asked to determine design criteria for weather protection systems for which it is likely impossible to calculate the freeze protection measure. It is true that heat trace applications do have a “design temperature” although experience has shown that this may not be accurately applied from one installation to the next, and likely deteriorates over time. Example of issues with this requirement:

 i.          what is the design temperature of a wind block for wind coming straight at the structure versus 90 degrees to the left or right?

ii.          What is the design temperature (with or without wind) for a temporary enclosure with a portable heater? Is there a significant difference if the source of the heat is electric, kerosene or LP gas? Wind can also blow out flames and carry heat away before it raises the temperature of the system the heater is there to protect.

During FERC’s April 2022 technical conference, one panelist stated that it may take several years to determine the point at which a temporary device fails. It is not clear under this requirement what is required to show the design capability. Based on these issues, is it technically feasible to have design documentation for a generator that uses any temporary devices, or does the Generator Owner say that it is technically infeasible to having design documentation until such time as the unit successfully (or unsuccessfully) operates through a severe cold weather event?

 

g.     Most engineering processes do not attempt to create 100 percent reliability. This is true for generator design to meet expected temperatures. Traditionally, generation was designed to meet some level of expectation below 100 percent. Meaning if the expected low temperature was 10 degrees F, the generator design may not have tried to meet that temperature 100 percent of the time. The design would be to have it reliable 97 percent of the time at that point, not have able to operate 100 percent at that point for an undetermined time.

For these reasons, the NAGF cannot recommend support for this requirement until the issues identified here are adequately addressed. The NAGF has provided a revised EOP-012-1 standard for consideration that address these issues in a reasonable manner.  Please note that the NAGF cannot recommend its member support a retrofit requirement in any way until such time as the compensation issue is addressed outside of the NERC process as recommended in the report. Until that occurs, the NAGF believe that NERC should focus its efforts on ensuring that the planners have and utilize the generator information needed to support improved planning processes

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

NAGF EOP-012-1 06152022 final.pdf

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The requirements of R1, without addressing Key Recommendation #2 in the November 2021 FERC/NERC report is the most significant concern of the Texas generators. Unfunded mandates of this economic magnitude that do not have proposed cost recovery will result in reduced generation available the winter season, at the least, and permanent retirement, at the worst. Neither of these outcomes will enhance grid reliability. Quite the opposite, this requirement will very likely reduce grid reliability by reducing available generation to the grid. Focus should be on Freeze protection measures, not full retrofits/redesign,  and should address only those critical components that could potentially trip/derate the unit. Root cause analysis of previous freeze-related outages have not revealed concerns for auxiliary systems that support operation but are considered part of balance-of-plant. These can be addressed through sound operational practices and startup prior to freeze events. In summary, retrofits of existing units should not include all operating systems and should not be required without some cost recovery realized.The SDT should consider ASHRE, a statistically-based standard which uses daily average temperatures, which has been accepted and used by industry for many years.  Finally, overdesigned cold weather protection will reduce hot weather reliability. Without practical limit to winter preparation, summer reliability may subsequently be reduced.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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In R1.1 it states “each generating unit shall be designed and maintained using the minimum hourly temperature since 1975…”  Concern is that expenditures will be required for a temperature that may occurs once in decades or is an anomaly. Perhaps a solution would be to determine the frequency of minimum hourly temperatures that occur in the time period.  The standard could read: “if an area has experienced at least 10 (or 5, or 8 or whatever) minimum hourly temperatures within a 10 degree range, ie (-10 to -20) (0 to -10), since 1975, the entity will use the lowest recorded hourly temperature that occurred within that range”.  This could also eliminate the need for Requirments R4.1 and R4.3, since the probability of hitting lower temperatures using the 10 degree range method in a 5 year period would be minimized.

 

Also R1.1 and R3.1 are redundant in wording….would flow better if the requirements are re-arranged, see comments for #10.

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

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Quintin Lee, Eversource Energy, 1, 6/20/2022

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CHPD agrees with LPPC's comments.

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

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Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #4.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

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MidAmerican supports EEI’s comments.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

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Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

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ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

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While SIGE supports efforts to ensure that existing generating units have the ability to continuously operating within their designed operating specifications in extreme temperatures (cold or hot); SIGE does not agree that generating units should be required to make modifications to meet certain freeze protection requirements beyone the expected designed operating specifications.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

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PPL NERC Registered Affiliates generally support EEI comments on Question 4, including the proposed language for R1 in the EEI comments.  In addition, PPL and LG&E and KU believe both proposed EOP-012-1 R1 language and alternative R1 proposed by EEI could be more clear on how the GO would demonstrate that units comply with the requirements for freeze protection measures with respect to the cooling effect of wind and impacts of precipitation, particularly for existing units (see question 5 for new units).  PPL and LG&E and KU recommend the wind and precipitation component of R1 be either removed (suggested language below) or the wind and precipitation criteria be more clearly defined.

1.1 Each generating unit shall be capable of continuous operations at the documented minimum hourly temperature experienced at its location since 1/1/1975, or a lesser period if reliable data is not available to 1975;

1.2 For each existing generating unit that requires either new freeze protection measures or modification of existing freeze protection measures, the Generator Owner shall develop and implement a Corrective Action Plan (CAP) which includes the following at a minimum:

1.2.1 An identification of corrective action (s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

1.2.2 A timetable for implementing the corrective action(s) from Part 1.2.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;

1.2.3 An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

1.2.4 In the event a GO is unable to fully mitigate their generating unit to have the continuous operating capability as defined under R1, a determination shall be made, where deemed appropriate by the Generator Owner based on their review of Parts 1.2.1 through 1.2.3, that no additional revisions to the cold weather preparedness plan(s) will be made and that no further corrective actions will be taken. The Generator Owner shall document the technical, commercial, or operational constraints as defined by the Generator owner as support for such determination.

 

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

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Requirement R1 would require the GO to implement new freeze protection measures or modify existing freeze protection measures if minimum criteria (part 1.1 through 1.3) are not met.  Is there a definition or parameters for what the extent of that protection boundary will be?  Will this apply to all climates or can GOs take graded approaches to the protective measures depending on the average temperature data?

 We recommend splitting R1 into two parts:

Rephrase R1 to “Each Generator Owner shall document an evaluation of freeze protection measures for their applicable generating units taking the following into account:

1.1. The documented minimum hourly temperature experienced at each generating unit’s location since 1/1/1975 (or a lesser period if reliable data is not available to 1975);

1.2. The cooling effect of wind based on each generating unit’s design; and

1.3. The impact on each generating unit’s operations due to precipitation (e.g.,sleet, snow, ice, and freezing rain).”

 Make the actions described in R1, part 1.4 a separate Requirement (new R2).  Possible wording:

“R2 Based on the evaluation of freeze protection measures performed under Requirement R1, each Generator Owner shall:

2.1 Determine if a generating unit requires new or modified freeze protection measures, and if so develop and implement a Corrective Action Plan (CAP) which includes the following at a minimum:

2.1.1. An identification of corrective action (s) for the affected unit(s), including any necessary modifications to the Generator Owner’s cold weather preparedness plan(s);

2.1.2 A timetable for implementing the corrective action(s) from Part 2.1.1 which considers any technical, commercial, or operational constraints, as defined by the Generator Owner;

2.1.3. An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

2.1.4. A declaration, where deemed appropriate by the Generator Owner based on the review of Parts 2.1.1 through 2.1.3, that no revisions to the cold weather preparedness plan(s) are required and that no further corrective actions will be taken. The Generator Owner shall document technical, commercial, or operational constraints as defined by the Generator Owner as support for such declaration.”

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

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FirstEnergy agrees with EEI’s comments.  

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

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The requirement has the following problems which should be addressed:

1) “Generating unit” defined simply as “Bulk Electric System Generator that… operate[s] during the winter season” needs further defining limitation. Should this only encompass the generator and its supporting structure? For example, is the powerhouse enclosing hydro units the boundary? Is the switchyard associated with a distributed generation aggregation point excluded? If the ERO later defines “generating unit” also includes all facilities the GO owns, such as the generation transmission interconnection line, is this intended by the SDT?

2) Hourly temperature may be a challenge to attain back to 1975. Suggest allowance of daily minimums and highs for historical records before the standard effective date since this data is more easily obtained and require hourly after the standard is implemented. The NOAA maintains numerous weather data collection sites and the GO should be able to utilize the nearest NOAA site to the generating unit location. This can be included within Measure M1. If the objective for hourly data is merly to document time spans temperatures are below freezing, state this and allow other forms of documentation. Retention of hourly data outside the area of concern adds unnecessary compliance burden.

3) Allow exemption for generation units that can demonstrate continuous operations through 5 days (not necessarily contiguous) where recorded temperature in Celsius was between -10 and 0 degrees or lower.

4) Stating “generation unit design” could create subjective audit interpretation as being from the generator manufacturer. Such data is not likely available for older units. Suggest revising requirement R1 to state “Each Generator Owner… implement mitigation measures at each generating unit for freeze protection based on the following minimum criteria.” Further, remove “generator unit design” from the subsections to clarify “design” refers to the mitigating measure.  For example: “design to enable continuous operations…” and “design shall account for…” This will allow for both generator modifications to its manufacturer design and measures to mitigate around manufacturer design parameters that can’t be changed.

5) Assure that failure of a mitigating measure is not a compliance violation. Please consider revising section 1.4 to make this clear, such as “should protective mitigating measures prove inadequate…”

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

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Portland General Electric Company supports the survey response provided by EEI.

PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

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Constellation agrees that generating units need to utilize sound practices for cold weather preparation.  Constellation suggests eliminating the wording “shall be designed and maintained to be”. Such wording is too prescriptive in how an entity is to ensure cold weather operation, and implies that a unit needs to be “re-designed”. If the intent is to ensure cold weather capability, suggest staying with “Each generating unit shall be capable of continuous operation....” to allow each generating unit to determine the manner in which the capability is to be achieved, depending on the particular circumstances of design, operation, and location of that unit.  Also the re-focus on "capable" allows requirement to include generators both existing and new, without use of wording such as "design", allowing a consolidation of the standard (see comments on R2 following.)

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

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Constellation agrees that generating units need to utilize sound practices for cold weather preparation.  Constellation suggests eliminating the wording “shall be designed and maintained to be”. Such wording is too prescriptive in how an entity is to ensure cold weather operation, and implies that a unit needs to be “re-designed”. If the intent is to ensure cold weather capability, suggest staying with “Each generating unit shall be capable of continuous operation....” to allow each generating unit to determine the manner in which the capability is to be achieved, depending on the particular circumstances of design, operation, and location of that unit.  Also the re-focus on "capable" allows requirement to include generators both existing and new, without use of wording such as "design", allowing a consolidation of the standard (see comments on R2 following.)

 

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

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Calpine has concerns with imposition of the R1 requirements, without Key Recommendation #2 in the November 2021 FERC/NERC, report being addressed. This requirement to implement new or modified freeze protection measures without a cost recovery mechanism proposes a significant economic burden on generators, and will result in reduced generation available the winter season; it could even result in permanent retirement due to the significant cost of compliance. These outcomes will reduce grid reliability by decreasing the amount of available generation to the grid. Calpine proposes that the SDT instead focus on Freeze protection measures rather than full retrofits/redesigns of existing units (which may or may not be feasible depending on unit age, design, technical, commercial or operational constraints). Additionally, the SDT requirement  should address only those critical components that could potentially trip offline or derate a generation unit due to sustained conditions. Root cause analyses of previous freeze-related outages have not revealed concerns for auxiliary systems that support operations, but are considered part of balance-of-plant equipment. Therefore, the focus should be on freeze protection of critical components only. These can be addressed through industry standard operational practices prior to freeze events. In summary, retrofits of existing units should not include all operating systems and should not be required without some cost recovery realized. Calpine agrees with Texas Competitive Power Advocates (TCPA)  in proposing that the SDT should consider ASHRE, a statistically-based standard which uses daily average temperatures, which has been accepted and used by industry for many years.  Finally, particularly in the Texas RE region, or other regions susceptible to severe hot weather peaks, overdesigned cold weather protection will reduce hot weather reliability when the grid is most likely to experience peak demand. Without practical limit to winter preparation, summer reliability may be substantially reduced.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

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CenterPoint Energy Houston Electric, LLC is not a registered Generator Owner or Generator Operator.

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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R1.4.4 is a critical requirement that recognizes the technical, commercial and operational constraints when implementing modifications to existing freeze protection measures.  Support for R1 is contingent on the retention of this specific requirement, as without it, Generators could face unreasonable commercial, technical or operational obstacles to maintaining compliance.

Natalie Johnson, Enel Green Power, 5, 6/21/2022

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The SRC finds certain aspects of the proposed language as too vague and invites a lack of consistency among generators even those geographically close to each other. In terms of documentation of temperatures, we suggest that the standard be revised to propose the use of NOAA data as the default in determining the minimum hourly temperature, otherwise, provide supporting documentation of data used in determining the minimum hourly temperature. “At its location” may be too ambiguous and doesn’t represent enough specificity to accurately define weather conditions.

The SRC proposes the following EOP-012-1 R1.1 language changes:

R1.1.    Each generating unit shall be designed and maintained to be capable of continuous operations at the documented minimum hourly temperature experienced at its nearest National Oceanic and Atmospheric Administration (NOAA) or its Environment and Climate Change (for generating units located in Canada) location since 1/1/1975 or a lesser period if reliable data is not available to 1975, should the generating unit wish to utilize a different source of weather information it shall provide documentation as to whether its source is equivalent or superior to the NOAA data as support for using this alternative data source, which documentation of temperature value shall be audited;

In addition, the SRC requests removing the ‘commercial’ reference in Requirements 1.4.2 and 1.4.4 as this language is vague, creates an ambiguity as to the obligation otherwise provided for in the standard, and a review of commercial issues is not within NERC’s domain and expertise.

R1.4.2. A timetable for implementing the corrective action(s) from Part 1.4.1 which considers any technical, or operational constraints, as defined by the Generator Owner;

R1.4.3. An identification of any temporary operating limitations that would apply until execution of the corrective action(s) identified in the CAP; and

R1.4.4. A declaration, where deemed appropriate by the Generator Owner    based on the review of Parts 1.4.1 through 1.4.3, that certain revisions to the cold weather preparedness plan(s) are not required and that certain corrective actions will not be taken. The Generator Owner shall document technical, or operational constraints as defined by the Generator Owner as support for such declaration.

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

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Q4. The proposed language in EOP-012-1 R1 causes concerns for ERCOT.  ERCOT generally supports the SRC comments provided; however, the SRC comments do not encompass all of ERCOT’s concerns.  These concerns are explicitly identified below and are followed by proposed language.  For clarity, ERCOT also addresses its concerns with the CAP and declaration/exemption in this response, as those issues are interrelated. 

  • R1, in general: should identify the Generator Owner as the entity taking action, not the generating unit.
  • R1.1: The use of the word “designed” may imply that existing generators should be redesigned to comply with the defined temperature standard. It is more accurate and more straightforward to phrase this as a capability requirement rather than a design requirement.
  • R1.1: Should require the GOs to use an objective source of historical temperature data to be implemented consistently across regions.
  • R1.2 and R1.3: Should be more explicitly tied to R1.1 and the ability to be capable of continuous operations. The FERC/NERC Report on the February 2021 Cold Weather Outages states that GOs should “understand how precipitation and the accelerated cooling effect of wind limit their generating unit’s performance.”  The Report further states that the February cold weather event demonstrated that ambient temperatures alone do not serve as a basis to predict whether a generating unit can perform during predicted cold weather.  Also, ERCOT urges the SDT to adopt a clear metric for wind speed and precipitation.  ERCOT is not presently proposing specific metrics.  If the SDT’s preference is to address this in Phase 2, ERCOT is comfortable with that.
  • R1.2 and R1.3: Similar to comment for R1.1, should not reference unit design.
  • R1.4: The meaning of “existing” will change over time.  If purpose is to limit this provision to those in existence at the time this rule goes into effect, as distinct from “new” generating units, which presumably enter operations at some later date, the language should say that. 
  • R1.4: Propose to remove CAP details from R1 and move to a standalone requirement, presented here as R7. It is more concise to have one CAP section since the need for a CAP could be triggered by several requirements.
  • R1.4: The CAP requirement should apply to all GOs, since any GO can discover an inability to comply at some point (even outside of the review required by R4 or the circumstances identified in R6). The modifications proposed also require the CAP to be implemented as soon as practicable with a reasonable window for actions with long lead times.
  • R1.4.2 (relocated to ERCOT proposed R7.2): Each timetable needs to identify the measures that will be implemented by each winter season.
  • R1.4.4: ERCOT provides language to replace the declaration language with explicit exemption language in a new R8.  If this is intended to operate as an exemption, that needs to be said explicitly, and it needs to be subject to some reasonable constraint.  Recommendation 1f in the FERC/NERC Report does not contemplate any sort of broad exception; however, ERCOT agrees that a narrow exception to avoid retirements is helpful.  ERCOT believes that the exemption language provided in R8 better achieves the purpose of the declaration while also improving on the concept by ensuring periodic reviews to ensure the constraint is still valid.

As noted, the revisions to the CAP and exemption language would also apply to R4 and R6. The comments and proposed language revisions to these requirements are as follows:

  • R4.1 and R4.2: Clarify that revisions to cold weather preparedness plan need to be made as necessary.
  • R4.3: Require a CAP using language similar to that used in R1.4. This addresses a potential gap of modifying the freeze protection measures to updated temperatures.
  • R6: Remove “within the Generation Owner’s control.” All GO equipment should be understood to be within the GO’s control, as ownership should determine ultimate legal control.  Otherwise, this would create a gap in the standards. If another party owns equipment at the site that could cause a failure, the GO can assign that party responsibility through contract. 
  • R6: Remove CAP details here in favor of general CAP provision in R7. Add similar CAP introduction language as seen in R1.4 and R4.3.
  • R6: Include subparts 6.1 and “similar” language from subpart 6.2.3 from the SDT proposed standard language in the main requirement to avoid the need to put the language in the CAP section (R7).
  • R6: This should reference the min hourly temp since 1/1/75, not the min capable operating temp in 3.4.2.

ALTERNATE LANGUAGE PROPOSED (REDLINE VERSION ATTACHED TO QUESTION 10)

R1.          Each Generator Owner shall implement freeze protection measures that ensure each of its generating units meet the following minimum criteria:

1.1.         Each generating unit shall be capable of continuous operation at the minimum hourly temperature recorded by the National Oceanic and Atmospheric Association or Environment and Climate Change Canada since January 1975 at the weather station nearest to the generator’s location;

1.2.         For purposes of identifying freeze protection measures needed to comply with Part 1.1, the Generator Operator shall account for the cooling effect of wind at XX mph;

1.3.         For purposes of identifying freeze protection measures needed to comply with Part 1.1, the Generator Operator shall account for the impacts of YY precipitation (e.g., sleet, snow, ice, and freezing rain); and

1.4.         If a Generator Owner determines that a generating unit requires either new freeze protection measures or modification of existing freeze protection measures to meet the standard established in Part 1.1, the Generator Owner shall develop a Corrective Action Plan (CAP) in accordance with Requirement R7.  The CAP shall be developed within 150 days of identifying the need for new or modified freeze protection measures and shall be implemented as soon as practicable but no later than three years from the date the deficiency was identified.

R4.          Once every five calendar year, each Generator Owner shall:

4.1.         Review the documented minimum hourly temperature developed pursuant to Part 3.1, and, if that temperature is no longer accurate, update the cold weather preparedness plan with the lowest temperature and make any necessary revisions to the plan based on that lower temperature;

4.2.         Review its documented cold weather minimum temperature contained within its cold weather preparedness plan(s) for its generating units, pursuant to Part 3.4.2, and update that value as necessary; and

4.3.         Review whether its generating units have the freeze protection measures required to comply with Requirement R1 and, if not, develop a CAP in accordance with R7 and implement the CAP as soon as practicable but no later than three years after identifying the need for new or modified freeze protection measures.

R6.          Each Generator Owner that owns a generating unit that experiences an event resulting in a derate of more than 10% of the total capacity of the unit for longer than four hours in duration, a start-up failure where the unit fails to synchronize within a specified start-up time, or a Forced Outage for which (i) the apparent cause(s) of the event is due to freezing of the Generator Owner’s equipment, and (ii) the ambient conditions at the site at the time of the event are at or above the temperature described in Part 1.1 shall develop a CAP, in accordance with R7, for each generating unit that experiences such a failure and for any other of the Generator Owner’s generating units that uses similar equipment that could reasonably be susceptible to a similar failure.  The CAP shall be developed within 150 days of the event or by the following July 1, whichever is earlier, and shall be implemented as soon as practicable but no later than three years from the date the CAP is developed.

R7. A Corrective Action Plan (CAP) required by this standard shall include at least the following:

7.1          An identification of corrective actions needed for the affected unit to comply with Requirement R1, including any necessary modifications to the Generator Owner’s cold weather preparedness plan;

7.2          A timetable for implementing the corrective actions from Part 1.4.1, Part 7.1, or Requirement R6, as applicable, which shall identify the measures that can reasonably be achieved before each successive winter season and the timetable for implementing each such measure, and documentation of the commercial, technical, or other reasons for the timetable provided;

7.3          An identification of any temporary operating limitations that would apply until execution of the corrective actions identified in the CAP;

7.4          Explanation of, and documentation for, any exemption claimed pursuant to Requirement R8; and

7.5          For any CAP required by Requirement R6, a summary of the identified cause(s) for the equipment freezing event, where applicable, and any relevant associated data.

R8.          Notwithstanding any other requirement in this standard, if a generating unit identified in Part 8.1 or 8.2 cannot comply with Requirement R1 due to a technical, commercial, or operational limitation, the generating unit shall be exempt from compliance with R1 to the extent of that limitation if the Generator Owner can provide documentation sufficient to demonstrate that limitation.  In the case of a commercial limitation, the Generator Owner shall provide documentation sufficient to demonstrate that the generating unit would reasonably be expected to operate at a financial loss on an annual basis if it were required to comply with the standard.  In each case, the Generator Owner shall ensure that the unit complies with Requirement R1 to the greatest extent of its capability.  This exemption applies only to the following generating units:

8.1          Any generating unit that began operating before the compliance date for Requirement R1, or

8.2          Any generating unit that began operating on or after the compliance date for Requirement R1, if the asserted technical, commercial, or operational limitation is attributable to either a lower minimum temperature experienced after the unit became operational or some other condition not reasonably foreseeable at the time the unit began operations. 

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

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SNPD supports comments submitted by LPPC and Tacoma Power

Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

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We suggest for the requirement to include cold weather frequency and duration of the criteria to determine if additional cold weather and freeze protection measures need to be implemented.  This would allow for generating units in tropical climates that may rarely experience momentary freezing temperatures to more cost effectively implement the standard.

Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

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LCRA agrees with Lthe North American Generator Forum comments and NRG Energy Inc. comments submitted 6/15/2022.  

Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

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LCRA agrees with Lthe North American Generator Forum comments and NRG Energy Inc. comments submitted 6/15/2022.

James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

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Hot Answers

TransAlta supports comments provided by NAGF.

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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We support LPPC's comments

John Babik, JEA, 5, 6/21/2022

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Other Answers

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

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Redundant information that a 5-year review is acceptable to be included.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

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 Technical reasons may be mitigated over time by development of newer technology or methods. Therefore, a review should occur. The frequency of five years may be too frequent, however. A definition of "new" generation should also be described in R2, and there should be clarification on when R2 does not apply. 

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

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Requirement R4 appears to already fullfill the requirement of R2. The 2 requirements should be merged into one.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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We operate in a cold weather envorpnment, the requirements for our facilities are site specific and are taken into account by the owner. We do not need this language in the standard.   

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

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SEC agrees with R2 as written and does not believe that a requirement for “new” generation is required.

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

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We believe that a review of “every six years” is more appropriate as it would align with our audit cycle or be reviewed every other audit.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

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A declaration that the GO cannot meet the constraints is good, but the Requirement does not specify to whom the declaration must be made. Is it simply a compliance document, or should the requirement specify that the impacted BA(s) be notified of the constraint? 

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

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R2 seems unnecessary and redundant.  This is covered by R1.4.4 and R4.3

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

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NRG believes that all new units should be subject to Requirement 1.1(based on criterion stated in Response to 4C), 1.2 and 1.3 for entry into the market and not be eligible for R2. This requirement as written should be considered and applied only to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. Existing units should be eligible for exemptions due to technical and operational constraints. Exemptions due to commercial concerns are unclear in the draft and need to more clearly defined.   The SDT should consider changing exception for commercial reasons to commercial/economic reasons as requirement that would make a unit uneconomic will result in mothball or retirement of the unit. Exceptions for uneconomic is needed to ensure that standards do not result in greater resource adequacy problems.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

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The IESO does not believe a separate requirement is necessary for ‘new generation’, as long as Requirement R4 covers all applicable generating units, and is wide enough in scope and content.
However, Generator Owners should be required to notify  the applicable  Balancing Authority of any CAP and its details, or its declaration of not taking corrective action and the technical or operational constraints to support such declaration.

 

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

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BPA supports the comments submitted by the US Bureau of Reclamation.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Requirement R2 seems unnecessary when considering Requirements R1.4.4 and R4.3. Neither Requirement R1 nor R4 stipulates the applicable facilities be either new or existing, so any generating plants constructed after the enforcement date of the Standard would be required to comply with R1.4.4 and R4.3. We recommend incorporating Requirement R2 into Requirement R1. Possible solutions are to remove the word, “existing” from the text of R1.4, or to create a new sub-requirement (R1.5.) to account for new generation within the construct of R1.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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NRG believes that all new units should be subject to Requirement 1.1(based on criterion stated in Response to 4C), 1.2 and 1.3 for entry into the market and not be eligible for R2. This requirement as written should be considered and applied only to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. Existing units should be eligible for exemptions due to technical and operational constraints. Exemptions due to commercial concerns are unclear in the draft and need to more clearly defined.   The SDT should consider changing the exception for commercial reasons to commercial/economic reasons.  If left unclear, the commercial exemption may not apply if following the requirement would not make economic sense, resulting in mothball or retirement of the unit. Exemptions for uneconomic reasons are needed to ensure that this standard does not result in greater resource adequacy problems.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Dominion Energy supports the EEI comments and agrees with the SDT that separate requirements are necessary for both new and existing generating units. Dominion Energy is of the opinion that some GOs may not have been sufficiently notified before making commercial commitments for key components, as a result of their approved interconnection agreement, and therefore may not be able to fully comply with the enhanced cold weather requirements similar to GOs with existing generating units.  For this reason, we suggest that where GOs who have either begun construction or purchased key components affecting their generating unit’s cold weather operational capability and were not properly notified of the enhanced cold weather requirements, should be afforded with a reasonable timeframe (i.e., 5-year reporting cycle) to remediate those issues and in some cases may have long term limitations similar to many existing generating units.  

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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The SDT should clarify when is a generator considered new and when is it considered existing.  In the future, once the Extreme Cold Weather Standards are approved and fully implemented, this distinction will be straightforward, but during the Implementation Period, GO/GOPs will be uncertain what category their generating units fall into.

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

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DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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No Additional Comments

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

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Reclamation recommends each unit that is unable to have freeze protection measures implemented be reviewed every 5 years on a rolling schedule, regardless of the age of the generating unit.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

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It is felt that this is a duplication of Requirement R2; thus R4 is not needed.

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

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WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

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Requirement R4 appears to already fullfill the requirement of R2. The 2 requirements should be merged into one.

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

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Requirement 4 provides sufficient coverage for new generation.

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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PG&E supports the comments provided by the North American Generators Forum (NAGF).

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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Texas RE does not think a separate requirement for new generation is necessary and has not typically been done in the NERC Reliability Standards.  New generation should be subject to the same requirements as existing generation in Requirement R4.  If Requirement R2 is upheld, the question would be when the new generation is not considered “new” and when the transition from Requirement R2 to Requirement R4 occurs.  Texas RE strongly recommends making clear that new generation shall perform EOP-012-1 R4 prior to the commercial operation date (COD) date as defined in the Registration Policy.  Texas RE recommends clarifying when a newly registered entity would be subject to compliance if it is registered during the time period after the effective date of the order, but prior to the compliance date for Requirements R1 and R2.  Please see Texas RE’s comments to question #9 regarding Requirement R4 periodicity.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

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NCPA, Segment(s) 4, 5, 6, 4/3/2020

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AEPCO signed on to ACES comments below:

Our answer is based upon not understanding the reason to carve out “new” generation from existing generation. We likely would be supportive of a separate requirement for “new” generation if appropriate justification for it can be provided by the SDT. If the term “new” generation continues to be utilized, we recommend the SDT develop a formal definition for the term.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

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AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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While Oncor is not a Generator Operator or Generator Owner, it does appears that R2 is redundant to R4 and therefore is not necessary.

Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

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NCPA agrees with the comments of NRG Energy, Inc.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

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Southern Company supports the EEI comments and believes the GO should be the sole entity to determine technical, operational, or operational constraints that would prohibit compliance from new units.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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Mark Young, Tenaska, Inc., 5, 6/16/2022

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We operate in a cold weather envorpnment, the requirements for our facilities are site specific and are taken into account by the owner. We do not need this language in the standard.   

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

- 0 - 0

NCPA agrees with the comments of NRG Energy, Inc.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

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A reference to new generation in this standard will add confusion, because a “new unit” soon becomes “existing generation” after it starts up. In addition, R2 as proposed is duplicative and would be satisfied with minor modifications to consider all units “existing generation.”  AEP does not believe this proposed, separate requirement is necessary for “new” generation.

In addition, AEP recommends that the five year cycle specified in R2 and R4 be revised to instead be a *maximum* five year cycle, in order to allow the Generator Operator adequate opportunity to align the cycle for all generating assets.

AEP supports EEI’s comments in their response to Question #5.

Thomas Foltz, AEP, 5, 6/17/2022

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Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

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No, an additional Requirement appears to be redundant; all GO’s should have this requirement.

Glenn Pressler, CPS Energy, 3, 6/17/2022

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Invenergy agrees that R2, as drafted, is redundant given R1 is applicable to all generating units, and R4 provides for a five year review of cold weather temperatures and freeze protection measures.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

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Invenergy agrees that R2, as drafted, is redundant given R1 is applicable to all generating units, and R4 provides for a five year review of cold weather temperatures and freeze protection measures.  

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

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No, an additional Requirement appears to be redundant; all GO’s should have this requirement. 

Robert Stevens, CPS Energy, 5, 6/17/2022

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Requirement R4 as currently drafted would not require GOs to review constraints previously documented pursuant to R2 (or R1.4.4 or R6); the separate requirement is therefore necessary.  As noted in our response to Question 4, we believe that the distinction between “new” and “existing” generators should be dropped, R1.4.4 deleted, and most of the text of R2 added (with appropriate edits) to R1 as R1.5.  R2’s five-year review requirement, however, should instead be moved to R4, as R4.4.  Doing so would have two benefits: it would consolidate the five-year reviews in a single Requirement for ease of reference, and it would allow GOs to perform all of their five-year reviews on the same cycle, rather than potentially tracking multiple staggered cycles.

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Requirement 2 is needed to address the documentation needed to substantiate whether the constraints related to new generating units not able to implement freeze protection measures still exist or apply after a 5 year duration. This particular review of determination is not necessarily addressed in R4. 

Michael Dillard, Austin Energy, 5, 6/17/2022

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ACP finds it difficult to respond “yes” or “no” to this question.  On the one hand, if R2 is removed, the remaining language would seem to suggest that new generation would be subject to doing a Corrective Action Plan under 1.4 as there would be no distinction between “new” and “existing.”  On the other hand, it is a bit confusing as originally drafted too in terms of what applies to “new” and what applies to “existing.”

As an alternative, ACP recommends relocating R2 under R1 as a new section 1.5.  That clarifies there is a single standard for all generation, but establishes separate compliance pathways for new and existing.  The SDT could also consider clarifying what is considered “new” and what is considered “existing.”  Perhaps a resource becomes existing upon the initial 5-year review period.

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

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It may be suitable to have parallel requirements for existing and new generators, but the way the draft is written, new generators get a loose, un-enforceable “opt-out” in R2 while existing generators have no such parallel requirement. We see two issues with this. First is that “technical, commercial or operational constraints” is so broad and ambiguous that either no one will have to comply with R1, or everyone will have to, depending on how auditors interpret the requirement. This is unacceptable. Second is that we see no parallel determination of technical, commercial or operational constraints for existing generators (which are far more likely to have these issues than new ones). As far as we can tell in the draft language for existing generators, the only determination is the low one hour temperature experienced at the site since 1975, and whether the unit will run in the “winter season”.

As to the question of whether the 5 year review would suffice to cover new generators, we believe any operating generator should have a “determination” on file and the 5 year review is only to re-assess units that already have a determination. So you would need something requiring new units to be evaluated before commercial operation.

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

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Summer Esquerre, NextEra Energy, 5, 6/17/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

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Requirement 4 provides sufficient coverage for new generation.

These comments have been endorsed by LPPC.

LPPC, Segment(s) 3, 1, 6/17/2022

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AZPS supports EEI’s comments and proposed revisions to R2.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

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Agree with the NAGF comments.

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

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Each unit that is unable to implement protection measures should be reviewed every 5 years, regardless of age or if it is a new or existing resource. 

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

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EEI does not agree that GOs should be given a separate requirement that allows them to, in perpetuity, have the ability to not meet the freeze protection measures set in EOP-012.  Accommodations for generating units that were approved for interconnection, or where key components in the design of the resource were already purchased prior the effective date of EOP-012, should be allowed to make a determination similar to what is provided for existing resources.  Otherwise, the generating resource should be designed and constructed to meet the cold weather standards set forth in EOP-012.  We suggest the following:

 

 R2.      Each Generator Owner who owns generating units that were placed into commercial operation on or after the effective date of the Standard shall design those units to have freeze protection measures based on the following minimum criteria set forth in Requirement R1, parts 1.1 & 1.2; except where the cold weather criteria contained in parts 1.1 & 1.2 was not conveyed to the owner as a condition of interconnection.  In these cases, 2.1 applies. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

2.1    The GO shall either modify their new generating unit in compliance with Requirement R1, parts 1.1 & 1.2, and report on their efforts to remediate all issues on a 5 year cycle, or in cases where the generating unit cannot be modified fully for documented technical, commercial, or operational constraints; the GO shall make a determination per Requirement R1, part 1.4.4.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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In five years’ time and in subsequent years, the generator would not be considered new, and Requirement 4 would cover those generators.

 

Additionally, we believe that allowing an exemption due to commercial constraints as defined by the GO is inconsistent with the concept of mandatory reliability standards. Operational constraints should be supported with a technical basis. All other operational limits are covered in R3. WECC would recommend consideration of replacing “commercial, or operational limitations” with “regulatory constraints.” WECC suggests similar wording changes throughout the standard. 

 

 

 

 

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Colorado Springs Utilities agrees with comments endorsed by LPPC

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

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No. While R4 should be maintained to clarify the review that is required every 5 years with respect to existing weather preparedness plans and freeze protection measures, there is no basis to exclude existing resources from the exceptions in R2, when existing resources are the ones more likely to encounter technical, commercial, or operational impediments to implementing the required freeze protection measures. Thus, R2 should be modified to include existing resources and allow for such resources to determine that they cannot meet the required cold weather preparedness and freeze protection standards for technical, commercial, or operational reasons and to review that determination every 5 years. This is especially important in regions like ERCOT, which has competitive generators that do not currently get any type of guaranteed cost recovery for implementation of freeze protection or weather preparedness standards. Imposing technically, commercially, or operationally infeasible burdens on such Generator Owners may cause or accelerate retirements of existing resources. Therefore, it is important for the standard to acknowledge that technical, commercial, and operational constraints are valid bases for allowing deviations from the draft standard for existing resources, so long as such constraints are documented and reviewed regularly, as proposed in R2.

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

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Entergy’s position is R4 encompasses all generation whether it is new or existing, which makes R2 unnecessary.

Entergy, Segment(s) 1, 5, 12/13/2017

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Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

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R2 should be employeed to capture all “new” generation, however 2.2 can be removed with the utilization of R4.  In addition, one needs to be concerned about the inclusion of commercial as a rationale for not completing freeze protection measures for new generators.  Does this provide an opportunity on the basis of cost not implement such measures?  if so, then the same latitude must be afforded existing units on the basis of cost until such time an adequate FERC compensation strategy is implemented.  Therefore, R4 should be further updated to be equivalent to the framework offered by R2.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

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R2 is not necessary.  Any new generation is subject to the design requirements of R1 and the review period of R4.

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

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Leave R2 as written and add the following to R2: …freeze protection measures for new “ and existing” generating unit(s)…

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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I agree with TAPs comments, pasted below:

Requirement R4 as currently drafted would not require GOs to review constraints previously documented pursuant to R2 (or R1.4.4 or R6); the separate requirement is therefore necessary.  As noted in our response to Question 4, we believe that the distinction between “new” and “existing” generators should be dropped, R1.4.4 deleted, and most of the text of R2 added (with appropriate edits) to R1 as R1.5.  R2’s five-year review requirement, however, should instead be moved to R4, as R4.4.  Doing so would have two benefits: it would consolidate the five-year reviews in a single Requirement for ease of reference, and it would allow GOs to perform all of their five-year reviews on the same cycle, rather than potentially tracking multiple staggered cycles.

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

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Michael Jones, National Grid USA, 1, 6/17/2022

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Xcel Energy supports the comments submitted by EEI.

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

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Requirement R4 as currently drafted would not require GOs to review constraints previously documented pursuant to R2 (or R1.4.4 or R6); the separate requirement is therefore necessary.  As noted in our response to Question 4, we believe that the distinction between “new” and “existing” generators should be dropped, R1.4.4 deleted, and most of the text of R2 added (with appropriate edits) to R1 as R1.5.  R2’s five-year review requirement, however, should instead be moved to R4, as R4.4.  Doing so would have two benefits: it would consolidate the five-year reviews in a single Requirement for ease of reference, and it would allow GOs to perform all of their five-year reviews on the same cycle, rather than potentially tracking multiple staggered cycles.

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

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Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

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We support LPPC's comments.

Joe McClung, JEA, 1, 6/17/2022

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PNM supports having the applicability of EOP-012-1 R4 be applicable to both “new” and “existing” generating units as stated in the comment provided by EEI.

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

- 0 - 0

All exceptions identified by Generator Owners that are submitted to NERC per proposed EOP-012, must be distributed to the applicable BA and TOP.    This not only includes the original exception, any subsequent status reports but also the results of the five year reviews.  If these units are not expected to be able to generate under specific weather conditions, and the BA and TOP are still expected to provide all necessary electric power, the BA and TOP need to know the status of all resources. 

Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

- 0 - 0

Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

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Capital Power supports the NAGF comments / concerns / suggested revisions related to this question.

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

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We do not agree that a new generator exemption is necessary.  We offer that generators, including wind turbines, have been effectively operating in the upper Great Plains, Canada, Sweden, and even Antarctica for many years.  If the SDT determines that it is necessary to retain the new generator exemption then we ask that they provide detailed justification why it is necessary.

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

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Requirement R4 appears to already fulfill the requirement of R2. The 2 requirements should be merged into one.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

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NAGF Comments: The SDT has not identified what determines a new generator versus an existing generator. Therefore, either the SDT must add information to the requirement to identify these units that qualify as new or treat all units the same, regardless of age. The NAGF recommends that all units be subject to the same requirements, so Requirement 2 is not needed.

The NAGF has provided a revised EOP-012-1standard for consideration that address these issues in a reasonable manner. Please review the proposed changes to the standard.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

NAGF EOP-012-1 06152022 final.pdf

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Differentiating between new and existing generation in R2 is not necessary. This requirement as written should be considered and applied only to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. Existing units should be eligible for exemptions due to technical and operational constraints. Exemptions due to commercial concerns are unclear in the draft and need to more clearly defined.   The SDT should consider changing exception for commercial reasons to commercial/economic reasons as requirement that would make a unit uneconomic will result in mothball or retirement of the unit. Exceptions for uneconomic is needed to ensure that standards do not result in greater resource adequacy problems.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

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Agree with ACES comments:  Our answer is based upon not understanding the reason to carve out “new” generation from existing generation. We likely would be supportive of a separate requirement for “new” generation if appropriate justification for it can be provided by the SDT. If the term “new” generation continues to be utilized, we recommend the SDT develop a formal definition for the term.

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

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Quintin Lee, Eversource Energy, 1, 6/20/2022

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CHPD agrees with LPPC's comments.

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

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Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #5.

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

MidAmerican supports the MRO NSRF’s comments. Requirement R2 seems unnecessary when considering Requirements R1.4.4 and R4.3. Neither Requirement R1 nor R4 stipulates the applicable facilities be either new or existing, so any generating plants constructed after the enforcement date of the Standard would be required to comply with R1.4.4 and R4.3. We recommend incorporating Requirement R2 into Requirement R1. Possible solutions are to remove the word, “existing” from the text of R1.4, or to create a new sub-requirement (R1.5.) to account for new generation within the construct of R1.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

- 0 - 0

Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

- 0 - 0

Our answer is based upon not understanding the reason to carve out “new” generation from existing generation. We likely would be supportive of a separate requirement for “new” generation if appropriate justification for it can be provided by the SDT. If the term “new” generation continues to be utilized, we recommend the SDT develop a formal definition for the term.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

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SIGE does not believe separate requirements are necessary for new and existing generating units. If R2 stays as is or ‘new’ is incorporated into R1, SIGE requests the SDT provide a definition of ‘new’ generation – is this since the effective date of the Standard or does it only apply for a certain amount of time after a unit is online? The definition may impact whether R2 is necessary or if it can be addressed by R1/R4.

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

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Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

- 0 - 0

PPL NERC Registered Affiliates generally support EEI comments on Question 5, including proposed language for R1 in the EEI comments. However, consistent with our comments on Question 4, PPL and LG&E and KU offer the following modification to the proposed language for Requirement 2. 

R2. Each Generator Owner who owns generating units that were placed into commercial operation on or after the effective date of the Standard shall design those units to have freeze protection measures based on the minimum criteria set forth in Requirement R1, parts 1.1 and 1.2 and including cooling effects of wind and freezing precipitation (e.g., sleet, snow, ice, and freezing rain) according to a relevant design standard selected by the GO for the units geographic location except where such cold weather criteria was not conveyed to the owner as a condition of interconnection.  In these cases, 2.1 applies.

2.1 The GO shall either modify their new generating unit in compliance with Requirement R1, parts 1.1 and1.2 and including cooling effects of wind and freezing precipitation (e.g., sleet, snow, ice and freezing rain) according to a relevant design standard selected by the GO for the unit’s geographic location, and report on their efforts to remediate all issues on a 5 year cycle, or in cases where the generating unit cannot be modified fully for documented technical, commercial, or operational constraints; the GO shall make a determination per Requirement R1, part 1.2.4.

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

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If R4 applies to all generation, this would include any new generation.  Interconnection studies for generation added to the BES should include provisions to meet these standards prior to commercial operations or with detailed schedule for compliance if approved for construction prior to the effective date of these requirements.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

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NV Energy supports EEIs comments:

EEI does not agree that GOs should be given a separate requirement that allows them to, in perpetuity, have the ability to not meet the freeze protection measures set in EOP-012.  Accommodations for generating units that were approved for interconnection, or where key components in the design of the resource were already purchased prior the effective date of EOP-012, should be allowed to make a determination similar to what is provided for existing resources.  Otherwise, the generating resource should be designed and constructed to meet the cold weather standards set forth in EOP-012.  We suggest the following:

 

 R2.      Each Generator Owner who owns generating units that were placed into commercial operation on or after the effective date of the Standard shall design those units to have freeze protection measures based on the following minimum criteria set forth in Requirement R1, parts 1.1, 1.2 & 1.3; except where the cold weather criteria contained in parts 1.1, 1.2 and 1.3 was not conveyed to the owner as a condition of interconnection.  In these cases, 2.1 applies. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning, Operations Planning]

2.1    The GO shall either modify their new generating unit in compliance with Requirement R1, parts 1.1, 1.2 and 1.3, and report on their efforts to remediate all issues on a 5 year cycle, or in cases where the generating unit cannot be modified fully for documented technical, commercial, or operational constraints; the GO shall make a determination per Requirement R1, part 1.4.4.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

- 0 - 0

FirstEnergy agrees with EEI’s comments.  FirstEnergy asks for clarification on when “new” generation would fall under the scope of R1.  

 

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

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CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

- 0 - 0

Advise combining the two requirements. In addition, should consider exemption for generation that has proven over decades of cold weather events, i.e., normal weather patterns regularly dip into extended freezing temperatures, that operations are minimally impacted. Performing cold weather contraint analysis periodically for generation units proven to have no problems over many years of operation serves no reliability purpose. 

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

- 0 - 0

PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

- 0 - 0

R2 should be combined with Requirement R1 and extend to any Generator not just new Generators.  As written, an entity has to be in violation of R1 to be able to leverage R2 to document its situation.  If retained, R2 should be an additional item in R1 where entities either have to meet the specs as set or document the reasons it cannot due to technical, commercial, or operational constraints.  R4 should be separately maintained, but should be revised to include periodic review of any determinations that the unit cannot implement the protections due to technical, commercial, or operational constraints.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

- 0 - 0

R2 should be combined with Requirement R1 and extend to any Generator not just new Generators.  As written, an entity has to be in violation of R1 to be able to leverage R2 to document its situation.  If retained, R2 should be an additional item in R1 where entities either have to meet the specs as set or document the reasons it cannot due to technical, commercial, or operational constraints.  R4 should be separately maintained, but should be revised to include periodic review of any determinations that the unit cannot implement the protections due to technical, commercial, or operational constraints.

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

- 0 - 0

It is not necessary to differentiate  between new and existing generation in R2. Additionally, this requirement should only apply to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. This is particularly important in regions like ERCOT with competitive generation, where generation owners do not currently have any mechanism for guaranteed cost recovery for implementation of such freeze protection measures. Existing units should also be eligible for exemptions due to technical and operational constraints, as long as these constraints are documented and regularly reviewed. Exemptions due to commercial concerns should be more clearly defined in the draft as they are currently uncelar, though Calpine proposes that the  exception for commercial reasons should also be modified to reflect commercial or economic reasons; i.e.  a requirement that would make a unit uneconomic such that it will result in mothball or retirement of the unit. Exceptions for economic purposes are needed to ensure that standards do not result in greater resource adequacy problems.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

CenterPoint Energy Houston Electric, LLC is not a registered Generator Owner or Generator Operator.

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

A separate requirement that recognizes the technical, commercial and operational constraints when implementing new freeze protection measures for a new site is helpful.  The process for implementing new freeze protection measures will be different from the process of modifying existing as there is no baseline to correct if it is a new design.  This difference can be addressed as a separate requirement for new and existing or another separate subrequirement under R1.  Either option can be used to address the different processes for implementation of freeze protection measures.  However it is unclear when a new site becomes an existing site.  Will there be a date threshold?  For example, sites that come online in 2022 are considered new, however, in 2025 are they still to be considered new or do the existing site requirements (R1.4) apply after a certain time.

Natalie Johnson, Enel Green Power, 5, 6/21/2022

- 0 - 0

The SRC’s recommendation is to continue a periodicity for “all” generating units to review its ongoing freeze protection measures and historical cold weather temperatures; and to provide a cost analysis of any technology that could be employed.  Any GO asserting an inability to implement freeze protection measures should be required to perform a periodic review at least every 5 years to demonstrate the constraint is still valid.

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

- 0 - 0

Q5. ERCOT supports the SRC comments. ERCOT does not believe R2 is necessary because new units would be covered by the general requirement in R1.  Also, because developers of units that will come into service after the compliance date of this standard (i.e., 5 years after FERC approval) should have full advance knowledge of the performance requirements, we see no legitimate reason for an exemption from this requirement, unless the impediment arose after the date the generator began operations.

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

- 0 - 0

SNPD supports comments submitted by LPPC and Tacoma Power

Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

- 0 - 0

A definition for New Generating Unit should be provided. As written, I would interpret that R2 would apply to new Generating Units in their first year. After the first year of operation, they will be considered existing Generating units, in which case R1.4 will apply.

Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

- 0 - 0

LCRA believes that all new units should be subject to Requirement 1.1 (based on criterion stated in Response to 4C), 1.2 and 1.3 for entry into the market and not be eligible for R2. This requirement as written should be considered and applied only to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. Existing units should be eligible for exemptions due to technical and operational constraints. Exemptions due to commercial concerns are unclear in the draft and need to be more clearly defined.   The SDT should consider changing the exception for commercial reasons to commercial/economic reasons.  If left unclear, the commercial exemption may not apply if following the requirement would not make economic sense, resulting in mothball or retirement of the unit. Exemptions for uneconomic reasons are needed to ensure that this standard does not result in greater resource adequacy problems.

Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

- 0 - 0

LCRA believes that all new units should be subject to Requirement 1.1(based on criterion stated in Response to 4C), 1.2 and 1.3 for entry into the market and not be eligible for R2. This requirement as written should be considered and applied only to the retrofit of existing units as it may not be economically feasible to retrofit these units to meet the requirements in Requirement 1.1, 1.2 and 1.3. Existing units should be eligible for exemptions due to technical and operational constraints. Exemptions due to commercial concerns are unclear in the draft and need to be more clearly defined.   The SDT should consider changing the exception for commercial reasons to commercial/economic reasons.  If left unclear, the commercial exemption may not apply if following the requirement would not make economic sense, resulting in mothball or retirement of the unit. Exemptions for uneconomic reasons are needed to ensure that this standard does not result in greater resource adequacy problems.  

James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

- 0 - 0

Hot Answers

TransAlta presented in preceding questions that we successfully operate in extreme cold in regions that do not have the type of reliability risk being addressed by this standard. Therefore, there should be no need for data requests. However, if a data request is required it would be best if the entities requesting have the discretion to determine in what regions/generators that information is useful and only request information of those entities. In addition, it is best if a centralized approach is taken as entities like ours operate in many regions and still manage requests and requirements on various platforms and portals which is still very challenging to manage, even with the advent of Align.

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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We support LPPC's comments

John Babik, JEA, 5, 6/21/2022

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Other Answers

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

- 0 - 0

No comment on what method is more effective.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

- 0 - 0

NA

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

- 0 - 0

We are questioning the added value for the specific operating context of some Canadian entities’ hydroelectric that have generation units already designed and operated in cold and extreme weather decades ago.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

- 0 - 0

This would not apply, based on our review for compliance with EOP 11-2 our plants have operated to conditions as low as experienced in the region (-22 deg F, -38.5 deg F when considering wind chill during that event) and we believe they could operate if the temperature decreased another 10 or 20 degrees. We are already in compliance with this standard so no data submittal for a compliance plan will be required.  

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

- 0 - 0

SEC does not believe that data requests are necessary. Has the SDT taken into consideration how many entities need to make modifications and the frequency of modification. The standard indicates entities already must have a plan.  This would be a burden on the entity and regulatory board reviewing this. SEC believes that the new standard addresses this concern in the requirements.

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

- 0 - 0

We agree with the collection of data under Section 1600 rather than from a standard requirement standpoint. However, we share the same concerns from other entities on the equipment included in the “generating unit” as some of the equipment may be in heated facilities or indoors where they may never see those temperatures. So, more clarity is needed to know what is in scope.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

- 0 - 0

Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

- 0 - 0

Section 1600

Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

- 0 - 0

VELCO abstains from commenting on the best procedural option, and trusts that the ERO Enterprise is best suited to make such a determination.

Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

- 0 - 0

Section 1600 would be appropriate until ERO could see that CAP efforts are complete. 

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

- 0 - 0

NRG agrees with comments made by the NAGF that Generator related capability data based upon progress of modifying units in accordance with implementation plan under Requirement 1.4 would not be as useful for identifying areas of potential concern than data directly from the planning entities, assuming the planning entities are using the information provided by the Generator Owners. This information is best provided by the Generator Owners to the Transmission Planner or Planning Coordinator (who use this info for the necessary planning studies) who can then provide it to the ERO, who can then provide it to FERC as desired.  This avoids duplicate and sometimes conflicting information.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

- 0 - 0

In addition to the ERO Enterprise collecting information on Generator Owner progress on its plans for modifying generating units, the same information should be provided to their respective Balancing Authorities.

 

Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

- 0 - 0

BPA supports the comments submitted by the US Bureau of Reclamation.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

- 0 - 0

Since both of these rules of procedures are a tool that the ERO can use to see CAP statuses, either is a valuable option for the ERO.

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

- 2 - 0

NRG agrees with comments made by the NAGF that Generator related capability data based upon progress of modifying units in accordance with implementation plan under Requirement 1.4 would not be as useful for identifying areas of potential concern than data directly from the planning entities, assuming the planning entities are using the information provided by the Generator Owners. This information is best provided by the Generator Owners to the Transmission Planner or Planning Coordinator (who use this info for the necessary planning studies) who can then provide it to the ERO, who can then provide it to FERC as desired.  This avoids duplicate and sometimes conflicting information.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

- 0 - 0

BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

- 0 - 0

Dominion Energy supports both EEI and NAGF comments and does not agree that Section 1600 could be used to collect entity information on their progress to modify affected generating units because the Rules of Procedure are clear that “Section 1600 shall not apply to Requirements contained in any Reliability Standard to provide data or information.”  CAPs are compliance obligations clearly defined by EOP-012.

 

For this reason, Section 400 of the Rules of Procedure should be used if this information is collected at all. Dominion Energy agrees with the NATF comments that this information being provided to NERC does not add a reliability benefit.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

- 0 - 0

This data collection should not be a mandatory Reliability Standard requirement, and would make more sense as a Periodic Data Submittal

Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

- 0 - 0

DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

- 0 - 0

ISO-NE has no preference as to the method of reporting, however any Generator cold weather data should be provided to the applicable RCs/BAs/TOPs/PCs/TPs.  The EROs already have a method to retrieve periodic data from the BAs under BAL-003.  A similar method could be used for the GO cold weather data.

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

- 0 - 0

Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

- 0 - 0

Reclamation does not agree there is a benefit to having the ERO Enterprise collect information on progress of Generator Owner plans for modifying generating units. Progress information is not required by any reliability standard. The ERO Enterprise does not collect information on the progress of implementing any other new standards. This type of data collection would be purely administrative and would not improve reliability.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

- 0 - 0

BHP is supportive of Section 400 or 1600 Reporting as opposed to mandatory reporting through a Reliability Standard Requirement.

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

- 0 - 0

WEC Energy Group supports EEIs comment in favor of Section 400 of the Rules of Procedure.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

- 0 - 0

We support the RSC comments. 

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

- 0 - 0

Tacoma Power prefers utilizing Section 1600 for data collection, similar to what was implemented for the GMD Standards Project.

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

- 0 - 0

PG&E supports the comments by the North American Generators Forum (NAGF) comments.

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

- 0 - 0

Texas RE recommends using Section 1600 of the Rules of Procedure, rather than the Periodic Data Submittal process.  This would eliminate possible PNCs from occurring due to Generator Owner engagement in PDS process.  This would also provide for a review by Reliability personnel, rather than Compliance personnel.  

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

- 0 - 0

NCPA, Segment(s) 4, 5, 6, 4/3/2020

- 0 - 0

AEPCO signed on to ACES comments below:

Periodic Data Submital under Section 400 of the Rules of Procedures.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

- 0 - 0

AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

- 0 - 0

N/A. Oncor is not registered as a Generator Owner/Operator.

Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

- 0 - 0

Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

- 0 - 0

NCPA does not believe there is reason to implement additional reporting requirements and agrees with the comments of NRG Energy, Inc.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

- 0 - 0

Southern Company supports the EEI comments but would like more clarity concerning the proposed methods of submitting information pertaining to EOP-012 and how that data would be collected/reported.

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

- 0 - 0

Periodic Data Submittal is the best method.

Mark Young, Tenaska, Inc., 5, 6/16/2022

- 0 - 0

This would not apply, based on our review for compliance with EOP 11-2 our plants have operated to conditions as low as experienced in the region (-22 deg F, -38.5 deg F when considering wind chill during that event) and we believe they could operate if the temperature decreased another 10 or 20 degrees. We are already in compliance with this standard so no data submittal for a compliance plan will be required.

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

- 0 - 0

NCPA does not believe there is reason to implement additional reporting requirements and agrees with the comments of NRG Energy, Inc.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

- 0 - 0

AEP believes it would be preferable for this information to be provided outside of NERC data requests, and instead be provided as part of attestations submitted to RTO’s in an agreed-upon format and schedule.

If NERC however does choose to make these data requests themselves, we would encourage that those requests not be unduly burdensome on industry in terms of either their detail or frequency. Between the two options suggested, AEP would prefer they be Section 400 requests. In addition, we don’t believe Section 1600 data requests would be appropriate in this case, as the ROP states that “the provisions of Section 1600 shall not apply to Requirements contained in any Reliability Standard to provide data or information.”

Thomas Foltz, AEP, 5, 6/17/2022

- 0 - 0

Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

- 0 - 0

We agree with the collection of data under Section 1600 rather than from a new standard requirement.  However, we have some concerns with what is included in the “generating unit” definition, so more clarity is needed to know what is in scope.

Glenn Pressler, CPS Energy, 3, 6/17/2022

- 0 - 0

Invenergy believes that a request for data in the ERO Portal under Section 1600 of the Rules of Procedure is the best procedural option for collecting Generator Owner information regarding the modification of its generating units per EOP-012-1 R1.  

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

- 0 - 0

Invenergy believes that a request for data in the ERO Portal under Section 1600 of the Rules of Procedure is the preferred procedural option for collecting Generator Owner information regarding the modification of its generating units per EOP-012-1 R1.   

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

- 0 - 0

We agree with the collection of data under Section 1600 rather than from a new standard requirement.  However, we have some concerns with what is included in the “generating unit” definition, so more clarity is needed to know what is in scope.

Robert Stevens, CPS Energy, 5, 6/17/2022

- 0 - 0

The information should be collected through a Periodic Data Submittal via the Align tool, which is already being used for other Periodic Data Submittals.  It should not be a Reliability Standard requirement.

Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

Section 1600 would be preferable

Michael Dillard, Austin Energy, 5, 6/17/2022

- 0 - 0

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

- 0 - 0

FMPA and members support TAPS comments on question 6

 

 

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

- 0 - 0

Summer Esquerre, NextEra Energy, 5, 6/17/2022

- 0 - 0

I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

- 0 - 0

LPPC prefers utilizing Section 1600 of the Rules of Procedure for data collection, similar to what was implemented with the GMD Standards Project, in which FERC simultaneously approved TPL-007-1 and directed the collection of data by way of Section 1600.

These comments have been endorsed by LPPC.

LPPC, Segment(s) 3, 1, 6/17/2022

- 2 - 0

AZPS supports EEI’s comments that Section 400 of the Rules of Procedure should be used.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

- 0 - 0

Agree with the NAGF comments.

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

While either of these options are tools at disposal of the ERO entertprise, progress information is not required by any reliability standard. The ERO Enterprise does not collect information on the progress of implementing any other new standards. This type of data collection would be purely administrative and would not improve reliability. Without additional information on how the data would be used beyond an administrative collection tool, it is not clear where the benefit lies.

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

- 0 - 0

A yes or no response does not conform to the question contained in Question 6, therefore, EEI has not selected either response.  Our response regarding a Section 400 vs. a Section 1600 data request is as provided below:

Section 1600 cannot be used to collect entity information on their progress to modify affected generating units because the Rules of Procedure are clear that “Section 1600 shall not apply to Requirements contained in any Reliability Standard to provide data or information.”  CAPs are compliance obligations clearly defined by EOP-012.

For this reason, Section 400 of the Rules of Procedure should be used.

 

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

- 0 - 0

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

- 0 - 0

Colorado Springs Utilities agrees with comments endorsed by LPPC

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

- 0 - 0

Luminant joins the comments of the Texas Competitive Power Advocates (TCPA) and does not have any additional comments on this question.

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

- 0 - 0

Entergy supports data submittal under Section 1600 of the Rules of Procedure.

Entergy, Segment(s) 1, 5, 12/13/2017

- 0 - 0

Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

- 0 - 0

PDS would be the best process for this status update.

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

- 0 - 0

IID prefers utilizing Section 1600 for data collection.   

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

- 0 - 0

Duke Energy suggest the aggregated data be collected through NERC Section 1600 — Request for Data or Information.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

- 0 - 0

I agree with TAPs comments, pasted below:

The information should be collected through a Periodic Data Submittal via the Align tool, which is already being used for other Periodic Data Submittals.  It should not be a Reliability Standard requirement.

Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

- 0 - 0

Michael Jones, National Grid USA, 1, 6/17/2022

- 0 - 0

Xcel Energy believes Section 400 of the Rules of Procedure is the appropriate avenue to collect this data.

Amy Casuscelli, On Behalf of: Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5; Gerry Huitt, Xcel Energy, Inc., 1,3,5

- 0 - 0

The information should be collected through a Periodic Data Submittal via the Align tool, which is already being used for other Periodic Data Submittals.  It should not be a Reliability Standard requirement.

Devon Tremont, Taunton Municipal Lighting Plant, 1, 6/17/2022

- 0 - 0

 We believe the report should follow Section 1600.

Santee Cooper, Segment(s) 1, 3, 5, 6, 6/17/2022

- 0 - 0

We support LPPC's comments.

Joe McClung, JEA, 1, 6/17/2022

- 0 - 0

Section 400 of the Rules of Procedure

Casey Perry, On Behalf of: PNM Resources - Public Service Company of New Mexico - WECC - Segments 3

- 0 - 0

Lindsay Wickizer, Berkshire Hathaway - PacifiCorp, 6, 6/17/2022

- 0 - 0

Minnesota Power supports MRO’s NERC Standards Review Forum’s (NSRF) comments and would recommend clarification on how this information is going to be used to verify which section of the Rules of Procedure should be referenced. 

Jamie Monette, On Behalf of: Allete - Minnesota Power, Inc., , Segments 1

- 0 - 0

Capital Power supports the NAGF comments / concerns / suggested revisions related to this question. Capital Power encourages NERC to focus on the facilitation of a centralized and consistent data portal for all of the regions (i.e. Align).

Shannon Ferdinand, Decatur Energy Center LLC, 5, 6/17/2022

- 0 - 0

As we discuss in our response to Q3 we believe that it is more important for the BAs to be active participants in defining the specified operating conditions, defining their need in MWs, and managing the data collection to ensure that their Operating Plans are in mesh with generator cold weather preparedness.  Reporting should flow through and by the BAs, not around.  

Mark Spencer, LS Power Development, LLC, 5, 6/17/2022

- 0 - 0

RSC abstains from commenting on the best procedural option and trusts that the ERO Enterprise is best suited to make such a determination.

NPCC Regional Standards Committee, Segment(s) 10, 2, 4, 7, 3, 1, 5, 6, 6/17/2022

- 0 - 0

NAGF Comments: The NAGF notes that information related to Generator weather capability should be used by the Transmission Planners, Planning Authorities, Balancing Authorities and Transmission Operators. To the extent that NERC and/or FERC wants information related to an area’s expected ability to survive an extreme weather event, the Transmission Planner or Planning Coordinator would be the better entity to provide this information to the ERO who can then provide it to FERC as desired. The NAGF notes that if the planners asked for and utilized information from the generators identifying the pertinent data, this information would be available in the processes already in place. Generator Owner level information is not as useful for identifying areas of potential concern than data directly from the planning entities, assuming the planning entities are using the information provided by the Generator Owners.

The NAGF has provided a revised EOP-012-1 standard for consideration that address these issues in a reasonable manner. Please review the proposed changes to the standard.

Wayne Sipperly, On Behalf of: North American Generator Forum, MRO, WECC, Texas RE, NPCC, SERC, RF, Segments 5

NAGF EOP-012-1 06152022 final.pdf

- 0 - 0

NERC does not need detailed information on progress on the CAP’s. Ultimately, the requirements of the EOP-012-1 require development of the CAP and implementing the CAP. The generator owners should be required to provide a timeline for units to be compliant with the RS but not periodic progress reports. An annual statement that the generator owner is on schedule with the CAP should be sufficient for NERC.

Michele Richmond, On Behalf of: Texas Competitive Power Advocates, Texas RE, Segments NA - Not Applicable

- 0 - 0

Please explain: Why it is important for the ERO Enterprise to have this information?  See additional comments under #7.

Donna Johnson, Oglethorpe Power Corporation, 5, 6/20/2022

- 0 - 0

Quintin Lee, Eversource Energy, 1, 6/20/2022

- 0 - 0

CHPD agrees with LPPC's comments.

PUD No. 1 of Chelan County, Segment(s) 3, 1, 6, 5, 6/20/2022

- 0 - 0

Evergy supports and includes by reference the comments of the Edison Electric Institute (EEI) for question #6.  

Alan Kloster, On Behalf of: Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Allen Klassen, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Marcus Moor, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6; Jennifer Flandermeyer, Evergy, 1,3,5,6

- 0 - 0

MidAmerican supports EEI’s comments. Section 1600 cannot be used to collect entity information on their progress to modify affected generating units because the Rules of Procedure are clear that “Section 1600 shall not apply to Requirements contained in any Reliability Standard to provide data or information.”  CAPs are compliance obligations clearly defined by EOP-012.

For this reason, Section 400 of the Rules of Procedure should be used.

Joseph Amato, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 6/20/2022

- 0 - 0

Exelon concurs with the comments submitted by the EEI.  

Submitted on behalf of Exelon (Segments 1 & 3)

Daniel Gacek, Exelon, 1, 6/20/2022

- 0 - 0

Periodic Data Submital under Section 400 of the Rules of Procedures.

ACES Standard Collaborations, Segment(s) 1, 3, 4, 5, 6/21/2022

- 0 - 0

Similar to other entities; SIGE would like clarity on what is in scope from a ‘generating unit’ standpoint. Additionally, if a ‘data submittal’ is required, the information is better suited for the Planning Coordinators as it may impact their studies. Their resulting studies could then be provided to the ERO.   

Leslie Hamby, On Behalf of: Southern Indiana Gas and Electric Co., RF, Segments 3, 5, 6

- 0 - 0

Oklahoma Gas and Electric agrees with and endorses comments as submitted by EEI Reliability Technical Committee (RTC)

OGE Energy - Oklahoma Gas and Electric Co., Segment(s) 1, 3, 5, 6/16/2022

- 0 - 0

PPL and LGE and KU support EEI comments on Question 6.

PPL NERC Registered Affiliates , Segment(s) 3, 5, 6, 1, 6/17/2022

- 0 - 0

We prefer a request for data under Section 1600 of the Rules of Procedure.

Dennis Chastain, On Behalf of: Tennessee Valley Authority - SERC - Segments 1, 3, 5, 6

- 0 - 0

NV Energy supports EEI’s comments. Section 1600 cannot be used to collect entity information on their progress to modify affected generating units because the Rules of Procedure are clear that “Section 1600 shall not apply to Requirements contained in any Reliability Standard to provide data or information.”  CAPs are compliance obligations clearly defined by EOP-012.

 

For this reason, Section 400 of the Rules of Procedure should be used.

Dwanique Spiller, Berkshire Hathaway - NV Energy, 5, 6/21/2022

- 0 - 0

FirstEnergy agrees with EEI’s comments and agree with the Data Submittal applying to Section 400 of the Rules of Procedure

FE Voter, Segment(s) 1, 3, 5, 6, 4, 12/20/2021

- 0 - 0

Section 1600. CSU supports LPPC's comments.

Hillary Dobson , Colorado Springs Utilities, 3, 6/21/2022

- 0 - 0

No is selected to indicate the SDT should avoid data collection for the ERO under a standard requirement unless a defined reliability gap is being addressed. If NERC determines a value in tracking progress of generation unit modification efforts, data collection should be under Section 1600 as developed by NERC, not the SDT. This allows the ERO to modify data collection as necessary, including termination without a standard revision. If compliance monitoring is the objective, then Section 400 is appropriate for requirements meeting reliability objectives.

Russell Noble, Cowlitz County PUD, 3, 6/21/2022

- 0 - 0

PGE FCD, Segment(s) 5, 1, 6, 6/21/2022

- 0 - 0

No new data collection process needs to be created by the Standard.  Processes currently exist to obtain this data, e.g., Section 1600 data requests, which allow pertinent data to be obtained as deemed necessary by the entities needing the data.  Without a confirmed need on the part of the proposed recipient of the data, the usefulness of data gathering and reporting is low.

 

Kimberly Turco on behalf of Constellation Segments 5 and 6

Alison Mackellar, Constellation, 5, 6/21/2022

- 0 - 0

No new data collection process needs to be created by the Standard.  Processes currently exist to obtain this data, e.g., Section 1600 data requests, which allow pertinent data to be obtained as deemed necessary by the entities needing the data.  Without a confirmed need on the part of the proposed recipient of the data, the usefulness of data gathering and reporting is low.

 

Kimberly Turco on behalf of Constellation Energy Segments 5 and 6

Kimberly Turco, Constellation, 6, 6/21/2022

- 0 - 0

I support comments made by Michael Dillard, Austin Energy, Segment 5

Jun Hua, Austin Energy, 4, 6/21/2022

- 0 - 0

Calpine joins the comments of the TCPA and does not have additional comments on this question.

Whitney Wallace, On Behalf of: Calpine Corporation, WECC, Texas RE, NPCC, SERC, RF, Segments 5

- 0 - 0

CenterPoint Energy Houston Electric, LLC is not a registered Generator Owner or Generator Operator.

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

- 0 - 0

Data requests are the preferred option under Section 1600 Rules of Procedures.  Similar to GADS and MIDAS, data submittal dates are scheduled and deadlines are provided to entities in advance and therefore submittal due dates and methods are consistent.  In addition, it is important to note that this type of data is not used for compliance evaluation purposes thereby enabling entities to keep their focus on meeting the requirements of the standard.      

Natalie Johnson, Enel Green Power, 5, 6/21/2022

- 0 - 0

In addition to the ERO Enterprise collecting information on Generator Owner progress on its plans for modifying generating units, the SRC is requesting this same information be provided to Regional Entities, Reliability Coordinators, Balancing Authorities, Planning Coordinators, Transmission Planners, and Transmission Operators.  An additional modification to EOP-012-1, along with a form for Generator Owners to populate, may be used similar to how data is collected in BAL-003-2 Frequency Response and Frequency Bias Setting Attachment A, where the ERO is able to collect data from Balancing Authorities on an established periodic basis. 

 

ISO/RTO Council (IRC) Standards Review Committee (SRC), Segment(s) 2, 6/21/2022

- 0 - 0

Q6. ERCOT supports the SRC comments. 

Dana Showalter, On Behalf of: Electric Reliability Council of Texas, Inc., , Segments 2

- 0 - 0

SNPD supports comments submitted by LPPC and Tacoma Power

Sam Nietfeld, Public Utility District No. 1 of Snohomish County, 5, 6/21/2022

- 0 - 0

Tony Skourtas, Los Angeles Department of Water and Power, 3, 6/21/2022

- 0 - 0

LCRA suggests GO data is best provided to regional Transmission Planner/Planning Coordinator for aggregation and provided to the ERO who can provide to FERC as desired. 

Teresa Krabe, Lower Colorado River Authority, 5, 6/21/2022

- 0 - 0

LCRA suggests GO data is best provided to regional Transmission Planner/Planning Coordinator for aggregation and provided to the ERO who can provide to FERC as desired. 

James Baldwin, Lower Colorado River Authority, 1, 6/21/2022

- 0 - 0

Q:

7. The drafting team has developed a proposed data collection framework which could form the basis for a periodic data submittal. If you have any comments or edits to the suggested language, please propose an alternative to address the identified risk during the phased-in compliance period.

Collection framework:

  • The Generator Owner will submit an annual summary table by October 1 of each year to its Regional Entity regarding the status of its generating units (as that term is used in EOP-012-1 4.2 Facilities) having freeze protection measures in accordance with Requirements R1 and R2, along with a nine-year projection of status based on the timetables it has determined for Requirement R1.  All projections will be based on the Generator Owner’s timetables under Requirement R1.4.2; if timetables are not complete for all units, some MW can be designated as “to be determined.”  The summary table shall contain:
    • Status year (for current year, and future years 1-9);
    • Sum of capacities (in MW) of all generating units applicable under Facilities, section 4.2;
    • Sum of capacities (MW) of generating units meeting (for current year) and projected to meet (for each of the future years 1-9) the criteria of Requirement R1.1;
    • Sum of capacities (MW) of generating units not meeting (for current year) and projected to not meet (for each of the future years 1-9) the criteria of Requirement R1.1;
    • Sum of the capacities (MW) of existing generating units declared for no action under Requirement R1 (for current year, and projected for future years 1-9);
    • Sum of the capacities (MW) of new generating units identified for no action under Requirement R2 (for current year, and projected for future years 1-9).
Hot Answers

These data requirements add to the administrative burden described in previous responses. There should not be any data requirement in regions where there is no reliability risk. However, if a data request is required, it is best if a centralized approach is taken as entities like ours operate in many regions and still manage requests and requirements on various platforms and portals which is still very challenging to manage, even with the advent of Align.

Ashley Scheelar, TransAlta Corporation, 5, 6/21/2022

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We support LPPC's comments

John Babik, JEA, 5, 6/21/2022

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Other Answers

In general, Idaho Power does not believe this level of tracking is needed. Idaho Power proposes an aggregated summary submittal to coincide every five years along with R4. Utilities with prior operating freeze issues should be subject to periodic reporting. 

Sean Steffensen, IDACORP - Idaho Power Company, 1, 6/2/2022

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The recording of units forced outage status and derates, will steer existing and new generation owners and operators to weatherize their units and auxillary systems, as it’s available capacity will affect the profitability to the units.  This incentive is the best driver to see the goal of generation reliability improved.

Nazra Gladu, Manitoba Hydro , 1, 6/7/2022

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 Recommend that this data request cover the listed bullets by primary fuel type to quickly identify trends.    

LaTroy Brumfield, American Transmission Company, LLC, 1, 6/8/2022

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We are questioning the added value of EOP-012 for the specific operating context of some Canadian entites’ hydroelectric generating units.

For Canadian entites, the necessary cold weather practices are already in place. The administrative burden associated to the tasks being required in the standards outweigh the reliability benefits, as we already have a good handle on planning, operations and maintenance activites in cold (and even extreme cold) weather.

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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We are already in compliance with the standard for all of our facilities and will not need to submit a compliance plan.

Glen Farmer, Avista - Avista Corporation, 5, 6/13/2022

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This seems duplicative of what entities already send to the RC and regional entity.

Kristine Ward, Seminole Electric Cooperative, Inc., 1, 6/14/2022

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Ok with the framework. This may also be added as data collection under Section 1600.

Israel Perez, On Behalf of: Salt River Project - WECC - Segments 1, 3, 5, 6

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Scott Kinney, Avista - Avista Corporation, 3, 6/15/2022

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Eric Sutlief, On Behalf of: CMS Energy - Consumers Energy Company - RF - Segments 3, 4, 5

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VELCO requests that SDT consider whether October 1 provides enough lead time to support the needs of BAs to make necessary preparations for the winter weather season. 

Randy Buswell, VELCO -Vermont Electric Power Company, Inc., 1, 6/15/2022

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N/A

Donna Wood, Tri-State G and T Association, Inc., 1, 6/15/2022

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If this is information the Planning Coordinators and Transmission Planners can use, then NRG would rather submit this information to the PC or TP who could then send it to the Regional Entity.  Generator Owners sending additional data to the Regional Entities duplicates work and may cause conflicting information.

Patricia Lynch, NRG - NRG Energy, Inc., 5, 6/15/2022

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Leonard Kula, Independent Electricity System Operator, 2, 6/15/2022

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BPA supports the comments submitted by the US Bureau of Reclamation.

Cain Braveheart, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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The SDT should not require this granular amount of data and a specific time frame, within this Standard.  If this type of information is required, perhaps it can be requested under the construct of question 6.  This will allow the RE to determine what highest risk generators that they want to review concerning any CAP progress.   

MRO NSRF, Segment(s) 2, 3, 5, 1, 4, 6, 4/11/2022

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If this is information the Planning Coordinators and Transmission Planners can use, then NRG would rather submit this information to the PC or TP who could then send it to the Regional Entity.  Generator Owners sending additional data to the Regional Entities duplicates work and may cause conflicting information.

Martin Sidor, NRG - NRG Energy, Inc., 6, 6/15/2022

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BC Hydro, Segment(s) 3, 5, 1, 12/18/2018

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Dominion Energy supports NAGF comments and does not support this reporting requirement.

Dominion, Segment(s) 3, 5, 1, 9/19/2019

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Brian Evans-Mongeon, Utility Services, Inc., 4, 6/16/2022

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DTE Electric supports NAGF comments.

DTE Energy - DTE Electric, Segment(s) 3, 5, 4, 12/8/2021

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ISO-NE supports the data collection and requests this information be submitted to the following entities: Regional Entities, Reliability Coordinators, Balancing Authorities, Planning Coordinators, Transmission Planners and Transmission Operators 

Keith Jonassen, On Behalf of: John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2; John Pearson, ISO New England, Inc., 2

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Alliant Energy supports the comments submitted by the MRO NSRF.

Larry Heckert, Alliant Energy Corporation Services, Inc., 4, 6/16/2022

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Reclamation does not support the proposed data collection. First, its purpose is not identified. Second, any reliability benefit it may provide is not identified. Therefore, it appears to be an additional ask of industry with no purpose and no benefit, which will only serve to detract already limited resources from implementing the newly required activities. Reclamation recommends NERC leverage the existing GADS reporting to satisfy this type of data collection.

Richard Jackson, U.S. Bureau of Reclamation, 1, 6/16/2022

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No alternative suggestions. The company would have ‘designed and implemented’ freeze protection measures into new facilities prior to commissioning.

Claudine Bates, Black Hills Corporation, 6, 6/16/2022

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WEC Energy Group supports EEIs comments.

Christine Kane, WEC Energy Group, Inc., 3, 6/16/2022

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We support the RSC comments. Additionally,

We are questioning the added value of EOP-012 for the specific operating context of some Canadian entites’ hydroelectric generating units.

This is an unnecessary administrative burden for all the generating units, especially Canadian entites’ generating units.

 

Nicolas Turcotte, Hydro-Qu?bec TransEnergie, 1, 6/16/2022

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The final guidance for the periodic data submittal should be inclusive of all generation types. For example, hydroelectric unit capacities are dependent on multiple factors and a unit may not operate to its full nameplate capacity. Based on the above, the guidance should specify whether the “sum of capacities” means the nameplate capacity or an estimate of the available capacity for the upcoming season.

Tacoma Power, Segment(s) 1, 3, 4, 5, 6, 3/9/2021

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PG&E supports the comments provided by the North American Generators Forum (NAGF).

PG&E All Segments, Segment(s) 1, 3, 5, 2/10/2020

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Texas RE recommends that it would be most useful for the GO to submit its annual summary table to its BA, rather than its Regional Entity since the Regional Entity would not have an action with the data.  This would support key recommendation 1g as it would give the BA the status of the generating units and the data could assist with determining the generating unit capacity that can be relied upon forecasted cold weather.  

Rachel Coyne, Texas Reliability Entity, Inc., 10, 6/16/2022

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NCPA, Segment(s) 4, 5, 6, 4/3/2020

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No comments at this time.

Jennifer Bray, Arizona Electric Power Cooperative, Inc., 1, 6/16/2022

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AECI and its members support comments provided by ACES.

AECI, Segment(s) 1, 3, 6, 5, 3/4/2021

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No Comments.

Gul Khan, On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1; Lee Maurer, Oncor Electric Delivery, 1

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Changes to Cold Weather Reliability Standards should not be applicable continent-wide.  Standards should not be modified or implemented prior to Market Rule Modifications.  See prior NERC Project 2019-06 ballot and commenting by Marty Hostler

Market Rule modifications have not yet been made to mitigate potential Cold Weather Events grid issues.  Per FERC/NERC's recommendation, Market Rule modifications should be made prior to, or concurrent with, development of new Standards.    To date, no known Market Rule Modification project has been initiated. 

On page 86 of  FERC/NERC's  joint Report The South Central United States Cold Weather Bulk Electric System Event of January 17, 2018 (ferc.gov) the following recommendations where made.  

Recommendation 1: The Team recommends a three-pronged approach to ensure Generator Owners/Generator Operators, Reliability Coordinators and Balancing Authorities prepare for cold weather conditions: 1) development or enhancement of one or more NERC Reliability Standards, 2) enhanced outreach to Generator Owners/Generator Operators, and 3) market (Independent System Operators/Regional Transmission Organizations) rules where appropriate. This three-pronged approach should be used to address the following needs: • The need for Generator Owners/Generator Operators to perform winterization activities on generating units to prepare for adverse cold weather, in order to maximize generator output and availability for BES reliability during these conditions. These preparations for cold weather should include Generator Owners/Generator Operators:

While any one of the three approaches may provide significant benefits in solving this problem, the Team does not view any one of the three as the only solution. The Team envisions that a successful resolution of the problem will likely involve concurrent use of all three.

Dennis Sismaet, Northern California Power Agency, 6, 6/16/2022

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NCPA does not support collection of this data and agrees with the comments of the U.S. Bureau of Reclaimation.

Jeremy Lawson, Northern California Power Agency, 5, 6/16/2022

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Southern Company supports the EEI comments and would include language to share this information with each generator’s applicable BA and RC.

 

Southern Company, Segment(s) 1, 3, 6, 5, 1/14/2021

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No comments

Mark Young, Tenaska, Inc., 5, 6/16/2022

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We are already in compliance with the standard for all of our facilities and will not need to submit a compliance plan. 

Mike Magruder, Avista - Avista Corporation, 1, 6/16/2022

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NCPA does not support collection of this data and agrees with the comments of the U.S. Bureau of Reclaimation.

NCPA, Segment(s) 3, 4, 6, 5, 4/20/2020

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AEP does not see a need to include the last bullet for “Sum of the capacities (MW) of new generating units identified for no action under Requirement R2 (for current year, and projected for future years 1-9)”, and recommends that it be deleted from the suggested list. We believe it is duplicative of the fourth bullet which states “Sum of capacities (MW) of generating units not meeting (for current year) and projected to not meet (for each of the future years 1-9) the criteria of Requirement R1.1.”

Thomas Foltz, AEP, 5, 6/17/2022

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Ameren agrees with the NAGF comments. 

David Jendras, Ameren - Ameren Services, 3, 6/17/2022

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This seems duplicative of what entities already send to the RC/BA, recommend RC/BA be required to send to the regional entity.  9-year requirement is too long and should be reduced to 5-year or less. 

The entirety of Standard EOP-012-1 should have a 5-year implementation plan.  The Generator Owners will need sufficient time to develop compliant procedures and practices.  Further, the scheduling and financing of modifications will require greater than 18 months.

Glenn Pressler, CPS Energy, 3, 6/17/2022

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Invenergy recommends coordinating the scope of the data request with BAs and other regulatory authorities who are making, and have already made, similar requests in order to reduce the administrative burden for Generator Owners.

Colin Chilcoat, Invenergy LLC, 6, 6/17/2022

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Invenergy recommends coordinating the scope of the data request with BAs and other regulatory authorities who are making, and have already made, similar requests in order to reduce the administrative burden for Generator Owners.  

 

Rhonda Jones, Invenergy LLC, 5, 6/17/2022

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This seems duplicative of what entities already send to the RC/BA, recommend RC/BA be required to send to the regional entity.  9-year requirement is too long and should be reduced to 5-year or less. 

The entirety of Standard EOP-012-1 should have a 5-year implementation plan.  The Generator Owners will need sufficient time to develop compliant procedures and practices.  Further, the scheduling and financing of modifications will require greater than 18 months.

Robert Stevens, CPS Energy, 5, 6/17/2022

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Rebecca Baldwin, On Behalf of: Transmission Access Policy Study Group, NA - Not Applicable, Segments NA - Not Applicable

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The guidance should specify whether the “sum of capacities” means the nameplate capacity or an estimate of the available capacity for the upcoming season

Michael Dillard, Austin Energy, 5, 6/17/2022

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ACP does not have an objection to the proposed data collection, however, we note that BAs and other regulatory authorities are requesting similar information.  ACP recommends coordination and collaboration happen between BAs, EROs, state PUCs etc. who are making similar requests in order to settle on a single set of data that GOs collect on extreme cold weather performance for submission to the various authorities.

Tom Vinson, On Behalf of: American Clean Power Association, , Segments 5

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This seems convoluted. Entities should not be reporting a 9 year projection, as this is  an odd number since planning studies go out to ten years. Some of these quantities don’t seem logical as a projection beyond year 1- We see no scenario where we would have a new plant in year 8 that we were projecting to not be able to meet freeze protection requirements. There is no language in R1 that discusses “no action”, is it the SDT’s intent that there is “no change from the prior year’s plan”?  

In general, FMPA supports the concept of reporting status but believe the RE should continue to be responsible for Periodic Data Submittals as they deem appropriate based on their forecasted risks.

FMPA and Members, Segment(s) 5, 4, 3, 6, 1, 6/17/2022

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Summer Esquerre, NextEra Energy, 5, 6/17/2022

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I support comments made by Michael Dillard, Austin Energy, Segment 5.

Lisa Martin, Austin Energy, 6, 6/17/2022

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The final guidance for the data collection (LPPC considers a Section 1600 data request more appropriate), should be inclusive of all generation types. For example, hydroelectric unit capacities are dependent on multiple factors and a unit may not operate to its full nameplate capacity. Based on the above, the guidance should specify whether the “sum of capacities” means the nameplate capacity or an estimate of the available capacity for the upcoming season.

These comments have been endorsed by LPPC.

LPPC, Segment(s) 3, 1, 6/17/2022

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AZPS supports the reporting proposal.

Michelle Amarantos, APS - Arizona Public Service Co., 5, 6/17/2022

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Agree with the NAGF comments.

Rick Stadtlander, On Behalf of: NEI, NA - Not Applicable, Segments NA - Not Applicable

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It remains unclear what the benefit of the proposed PDS would offer. Its purpose is not identified. Any reliability benefit it may provide is not identified. Therefore, it appears to be an additional ask of industry with no purpose and no benefit, which will only serve to detract already limited resources from implementing the newly required activities. Other reporting tools, such as GADS, exist to satisfy this type of data collection.

Kimberly Bentley, On Behalf of: sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6; sean erickson, Western Area Power Administration, 1,6

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EEI supports the reporting proposal as submitted. 

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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If a timetable is specified in R1, Part 1.4.2, it seems that including the phrase “to be determine” is not necessary. WECC offers the following language as an option for consideration. “All projections will be based on the GO’s timetable under Requirement R1, Part 1.4.2. If timetables are not finalized for all units, the GO may provide an estimate for completion or list the end date of the implementation plan.

 

WECC Entity Monitoring, Segment(s) 10, 1/30/2022

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Colorado Springs Utilities agrees with comments endorsed by LPPC

Mike Braunstein, Colorado Springs Utilities, 1, 6/17/2022

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Luminant has no comments on this question.

Dan Roethemeyer, Vistra Energy, 5, 6/17/2022

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Entergy requests clarification on the definition of capacity.  Entergy also recommends a 1-5 year future projection as opposed to 1-9 year.  Separating new and existing generating units doesn’t add value.

Entergy, Segment(s) 1, 5, 12/13/2017

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Acciona Energy supports Midwest Reliability Organization’s (MRO) NERC Standards Review Forum’s (NSRF) comments on this question.

George Brown, Acciona Energy North America, 5, 6/17/2022

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None

Gerry Adamski, Cogentrix Energy Power Management, LLC, 5, 6/17/2022

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But should not be required if the units are exempt from from EOP-012-1 as IID proposes.

Diana Torres, Imperial Irrigation District, 6, 6/17/2022

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Duke Energy suggest the following modifications:

Add the word “existing” to Bullet #1:  …table by October 1 of each year to its Regional Entity regarding the status of its “existing” generating units…

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Michael Watt, Oklahoma Municipal Power Authority, 4, 6/17/2022

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Michael Jones, National Grid USA, 1, 6/17/2022